Exhibit
1     RENEWAL ANNUAL INFORMATION
FORM   For the year ended December
31, 2003   April 22, 2004  
   TABLE OF
CONTENTS  GLOSSARY OF TERMSABBREVIATIONS AND
  CONVERSIONSPRESENTATION
  OF ENERPLUS OIL AND GAS RESERVES AND PRODUCTION INFORMATIONPRESENTATION
  OF ENERPLUS FINANCIAL INFORMATIONDESCRIPTION OF
  DISTRIBUTABLE INCOMEFORWARD-LOOKING STATEMENTSSTRUCTURE OF
  ENERPLUS RESOURCES FUNDGENERAL
  DEVELOPMENT OF ENERPLUS RESOURCES FUNDHistorical
  OverviewRecent
  Developments Since Fiscal Year-EndOIL AND NATURAL GAS
  RESERVESReconciliation of ReservesReconciliation
  of Changes in Net Present Value of Future Net RevenueOPERATIONAL INFORMATIONDescription of
  Principal PropertiesSummary of Production
  LocationsOil
  and Natural Gas Wells and Unproved PropertiesDevelopment
  ActivitiesQuarterly Production
  HistoryQuarterly Netback HistoryAbandonment and
  Reclamation CostsTax HorizonCosts IncurredMarketing
  Arrangements and Forward ContractsEnvironment, Health and
  SafetyImpact
  of Environmental Protection RequirementsAdditional
  Operational InformationINFORMATION
  RESPECTING ENERPLUS RESOURCES FUNDDescription
  of the Trust Units and the Trust IndentureDescription
  of the Royalty Agreements and Subordinated NoteManagement and
  Corporate GovernanceUnitholder
  Rights PlanDISTRIBUTIONS TO
  UNITHOLDERSINDUSTRY CONDITIONSRISK FACTORSSELECTED
  CONSOLIDATED FINANCIAL INFORMATION  i 
   MANAGEMENTS
  DISCUSSION AND ANALYSISMARKET FOR SECURITIESDIRECTORS AND OFFICERSINTEREST
  OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONSMATERIAL CONTRACTSINTERESTS OF EXPERTSREGISTRAR AND TRANSFER
  AGENTADDITIONAL INFORMATIONAPPENDIX A   REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
  EVALUATORAPPENDIX B   REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
  INFORMATION  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.  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;  EOG 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;  NI
51-101 means National Instrument 51-101, Standards of Disclosure
for Oil and Gas Activities, adopted by the Canadian securities regulatory
authorities;  Sproule
means Sproule Associates Limited, independent petroleum consultants;  Sproule
Report means the independent engineering evaluations of
Enerplus oil, NGLs and natural gas interests prepared by Sproule dated March
19, 2004 and effective January 1, 2004, utilizing commodity price forecasts of
Sproule dated January 1, 2004;  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.  iii 
   ABBREVIATIONS AND CONVERSIONS  In this Annual Information Form, the following abbreviations have the
meanings set forth below.  AECO
  
  Alberta Energy Company interconnect with the Nova
  System, the Canadian benchmark for natural gas pricing purposesbbls
  
  barrels, with each barrel representing 34.972
  Imperial gallons or 42 U.S. gallonsbbls/d
  
  barrels per dayBcf
  
  billion cubic feetBcf/d
  
  billion cubic feet per dayBOE
  
  barrels of oil equivalent converting 6 Mcf of
  natural gas to one barrel of oil equivalent and one barrel of natural gas
  liquids to one barrel of oil equivalent. The factor used to convert natural
  gas and natural gas liquids to oil equivalent is not based on either energy
  content or prices but is a commonly used industry benchmark.BOE/d
  
  barrels of oil equivalent per dayGJ
  
  gigajoulesMbbls
  
  one thousand barrelsMBOE
  
  one thousand barrels of oil equivalentMcf
  
  one thousand cubic feetMcf/d
  
  one thousand cubic feet per dayMMbbls
  
  one million barrelsMMBOE
  
  one million barrels of oil equivalentMMBTU
  
  one million British Thermal UnitsMMcf
  
  one million cubic feetMMcf/d
  
  one million cubic feet per dayMW
  
  megawatts of electricityNGLs
  
  natural gas liquidsWTI
  
  West Texas Intermediate at Cushing, Oklahoma, the
  benchmark for North American crude oil pricing purposes  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
  ByMcf
  
  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
  iv 
   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 (as defined below) basis,
unless indicated that they have been presented on a gross or net basis.
Enerplus actual oil and natural gas reserves and future production will be
greater than or less than the estimates provided in this Annual Information
Form.  The estimated future net revenue
from the production of Enerplus oil and natural gas reserves do 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 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 cash flow 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.  Although the Sproule Report is effective January 1,
2004, Sproule has confirmed that the information contained in the Sproule
Report would be identical if it were presented effective December 31, 2003, the
fiscal year-end of the Fund. As a result, throughout this Annual Information
Form, an effective date of December 31, 2003 has been utilized so that the
effective date of Enerplus oil and gas reserves information coincides with the
Funds fiscal year-end as contemplated in NI 51-101.  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 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 Associates Limited attached hereto as Exhibit A and
the Report of Management and Directors on Oil and Gas Disclosure attached
hereto as Exhibit B.  The effective
date for the Statement of Reserves Data and Other Oil and Gas Information
contained in this Annual Information Form is December 31, 2003 and the
information contained in the Annual Information Form has been prepared as of
April 22, 2004.  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) prepared jointly by The Society of
Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of
Mining, Metallurgy & Petroleum (Petroleum Society) (the COGE Handbook)
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.  v 
   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 those 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.  vi 
   Developed
Producing Reserves are those reserves that are expected to be
recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing
or, if shut-in, they must have previously been on production, and the date of
resumption of production must be known with reasonable certainty.  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 prices and costs used in an estimate that are:  (i)Enerplus
prices and costs as at December 31, 2003, 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).  Calculation of Reserve Life Index  Reserve Life Index means the amount obtained by
dividing the quantity of a particular category of reserves by Sproules
forecast of the first years production for the corresponding reserve category.  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 generally
accepted accounting principles (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 12 to the Funds
audited consolidated financial statements for the year ended December 31, 2003.  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 generally accepted accounting principles (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, incorporated by reference herein.  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.  Enerplus
disclaims any responsibility to update these forward-looking statements.  viii 
   ENERPLUS
RESOURCES FUND  Renewal
Annual Information Form
For the year ended December 31, 2003  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 and EOG), 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 EOG, respectively.  The head, principal and registered office of
Enerplus is located at The Dome Tower, Suite 3000, 333 - 7th Avenue
S.W., Calgary, Alberta, T2P 2Z1.  The
Trustee of the Fund is CIBC Mellon Trust Company located at 600 The Dome Tower,
333  7th Avenue S.W., Calgary, Alberta T2P 2Z1.  The Funds primary focus is to maintain and enhance
cash distributions to its unitholders through the development of its operating
subsidiaries existing crude oil and natural gas properties, the acquisition of
new producing properties and the monetization, by the way of sale or farm out,
of its operating subsidiaries higher risk exploration opportunities.  Development efforts are concentrated on
optimizing production from existing and new crude oil and natural gas reserves.  EnerMark Inc.,
Enerplus Resources Corporation and Enerplus Oil & Gas Ltd.  Each of EnerMark, ERC and EOG are corporations
organized under the Business Corporations Act (Alberta).  All of the issued and outstanding common
shares of EnerMark are owned by the Fund, all of the issued and outstanding
common shares of ERC are owned by EnerMark and all of the issued and
outstanding common shares of EOG are owned by ERC.The board of directors of EnerMark is responsible for the
governance of Enerplus.  EnerMark, ERC and EOG, 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 flows of cash from
EnerMark, ERC and EOG 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 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.-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.  3 
   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 $167.6 million, before final working
capital adjustments and costs of the acquisition.  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 $3.2 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.  2003 Acquisition and Disposition
Activity  Enerplus continually pursues and evaluates potential
acquisitions of oil and natural gas properties, companies, trusts and other
energy-related assets as part of its ongoing acquisition program.  Acquisition activities during 2003 (which
includes the above-described PCC acquisition but excludes the Ice Energy
acquisition described below) added approximately 5,595 BOE/d of production and
28.1 MMBOE of Proved plus Probable Reserves to Enerplus at an aggregate cost of
$225.3 million.  Enerplus routinely evaluates its property portfolio
and disposes of properties that are viewed as higher-risk, non-core
holdings.  In 2003, Enerplus divested
$73.2 million of non-core properties that produced approximately 3,033 BOE/d
and contained 9.2 MMBOE of Proved plus Probable Reserves.  Recent
Developments Since Fiscal Year-End  Non-Resident Ownership, Mutual Fund
Trust Status and Impact of 2004 Canadian Federal Government Budget Proposals  Since its listing on the New York Stock Exchange in
November of 2000, Enerplus has seen increased interest in its Trust Units, both
in terms of trading volumes and level of ownership, by persons who are not
residents of Canada.  Based on the most
recent information obtained by Enerplus through its transfer agent and
financial intermediaries in February 2004,an estimated 64% of the issued and
outstanding Trust Units were held by non-residents of Canada at that time.  As a result of the current structure and
assets of the Fund, Enerplus meets the mutual fund trust status requirements
under the Tax Act by reason of an exception to certain provisions within the
Tax Act which would otherwise restrict non-resident ownership of the units of a
mutual fund trust. 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. However, on March 23, 2004 the Canadian federal government
tabled its budget which proposed certain amendments to the Tax Act which, if
implemented in their present form, would affect Canadian mutual fund trusts. In
particular, one proposed amendment would effectively eliminate, over a period
of time, the exception currently relied on by Enerplus regarding non-resident
ownership restrictions and require the Fund to comply with the requirement that
it not be maintained primarily for the benefit of non-residents before
January 1, 2007.  If the proposed
amendment is enacted, Enerplus intends to comply with the requirements to
maintain its mutual fund trust status. 
Enerplus is reviewing various alternatives to mitigate the impact of
this legislation as it is currently proposed. 
Enerplus has in excess of two and one-half years to pursue and implement
strategies in this regard.  4 
   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. Enerplus has not currently implemented any
non-resident ownership or trading restrictions. However, the Funds Trust
Indenture includes provisions that allow the board of directors of EnerMark to
adopt non-resident ownership constraints if required in order to ensure that
the Fund maintains its mutual fund trust status. See Information Respecting
Enerplus Resources Fund - Description of the Trust Units and the Trust
Indenture  Non-Resident Ownership Provisions.  Should such a situation occur and Enerplus is unsuccessful in
mitigating these circumstances, the directors 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. 
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 (generally chosen in the inverse order of
acquisition or registration of the Trust Units) 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. For additional
information regarding these matters, including the consequences if the Fund
lost its mutual fund trust status, see 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 in this Annual Information Form.  Another proposal contained in the Canadian federal
governments 2004 budget would affect the taxation of distributions to
non-resident unitholders. An estimated 15% of the Funds current distributions
to non-resident unitholders are deemed to be a return of capital, which are not
subject to Canadian withholding tax.  It
has been proposed that a Canadian withholding tax be applied to the return of
capital portion of distributions made after 2004 to non-resident
investors.  Under this proposal, the
tax, at a rate of 15%, would be withheld from the distributions at source.  The budget also introduces an amendment to limit the
level of investment by pension funds in business income trusts after 2004.  This should not impact Enerplus, as it is
not currently considered a business income trust for the purposes of these
rules.  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, was approximately $132.2 million.  Ice Energy was a non-public oil and natural gas
company focused on shallow natural gas development in Alberta and
Saskatchewan.  Ice Energys production
at the time the transaction was completed was approximately 2,300 BOE/d,
comprised almost entirely of natural gas. Enerplus internal engineering
estimates attributed 13.9 MMBOE of Proved plus Probable Reserves to Ice Energy
at November 1, 2003, comprised of 80,034 MMcf of natural gas and 516 Mbbls of
crude oil and NGLs.  Also included in
the acquisition were 72,500 net acres of undeveloped land.  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.  The oil and natural gas reserves of Ice Energy
acquired by Enerplus are not included in Enerplus reserve information under
the heading Oil and Natural Gas Reserves, and the production and other
operational information attributable to the acquired Ice Energy properties has
been included in Enerplus results since January 7, 2004 but is not included in
the information contained in this Annual Information Form as the transaction
was completed in 2004.  5 
   Joslyn Creek Oil Sands SAGD
Development  Enerplus is positioned to participate in the future
development of Canadas oil sands reserves through its ownership of a 16%
working interest in Oil Sands Lease #24 (Joslyn Creek) acquired in 2002 for
approximately $16.4 million. Located in the Athabasca Oil Sands fairway of
northeastern Alberta near other significant oil sands projects, Joslyn Creek
has both steam-assisted gravity drainage (SAGD) and mining potential. To
date, several hundred core holes have been drilled and evaluated on the lease
to quantify the resource potential. Based on the results of this initial
evaluation, Enerplus and its working interest partners in Joslyn Creek are
pursuing a pilot SAGD project on the lease. Phase one of the SAGD commercial
project is currently being completed and is expected to produce 600 bbls/d.
Enerplus expects initial production from this phase to occur in the second
quarter of 2004 with peak production expected in 2005.  Following the pilot project, Enerplus
currently anticipates pursuing a full-scale 10,000 bbl/d project to be
completed and producing by 2007.  On April 1, 2004, the operator of the project announced the results of
certain reserves and resource studies on the Joslyn Creek project. The studies
confirmed the presence of significant quantities of commercially recoverable
bitumen on the project.  An independent
reserves evaluation effective December 31, 2003 conducted in accordance with NI
51-101 attributed 298 MMBOE of gross Probable Reserves to the SAGD portion of
the Joslyn Creek project, which would result in 47.6 MMBOE of gross Probable
Reserves being attributed to Enerplus 16% working interest in the
project.  Enerplus did not include any
SAGD reserves from the Joslyn Creek project in its 2003 year-end reserves described
under Oil and Natural Gas Reserves. Enerplus currently intends to include
these reserves in its 2004 year-end reserves evaluation pending a review of the
2004 results of the first phase of the SAGD pilot project.  6 
   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, has evaluated crude oil and natural gas properties which comprise
approximately 87% of Enerplus Proved Developed Producing crude oil and natural
gas reserves value discounted at 10%, and 86% of Enerplus Proved plus Probable
oil and natural gas reserves value discounted at 10%. Enerplus has evaluated
the balance of the properties using similar evaluation parameters, including
the same forecast price and cost assumptions utilized by Sproule. Sproule has
reviewed Enerplus evaluation of these properties.  In preparing its report, Sproule obtained basic
information from Enerplus, which included production and land data, well
information, geological information, reservoir studies, estimates of on-stream
dates, contract information, current hydrocarbon product prices, operating cost
data, capital budget forecasts, financial data and future operating plans.  Other engineering, geological or economic
data required to conduct the evaluation and upon which the Sproule Report is
based, was obtained from public records, other operators and from Sproules
non-confidential files.  Information
concerning the extent and character of ownership of Enerplus interests and the
accuracy of all factual data supplied to Sproule by third parties was accepted
by Sproule as represented and neither title searches nor field inspections were
conducted.  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 is a summary, as at December 31, 2003 of
Enerplus crude 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 following reserves
information does not include any reserve volumes or values attributed to Ice
Energy Limited (acquired by Enerplus in early January 2004) or Enerplus
interest in the Joslyn Creek oil sands project.The tables summarize the
data contained in the evaluations and as a result may contain slightly
different numbers than the evaluations 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 and
there is no guarantee that the estimated reserves will be recovered. 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.  7 
   Summary
of Oil and Gas Reserves
and Net Present Values of Future Net Revenue
As of December 31, 2003  Forecast Prices and Costs  OIL AND
  GAS RESERVESLIGHT AND
  MEDIUM OIL
  
  HEAVY
  OIL
  
  NATURAL
  GASRESERVES
  CATEGORY
  
  Company
  Interest
  
  Gross
  
  Net
  
  Company
  Interest
  
  Gross
  
  Net
  
  Company
  Interest
  
  Gross
  
  Net(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Bcf)
  
  (Bcf)
  
  (Bcf)Proved ReservesProved Developed
  Producing
  
  64,288
  
  63,570
  
  58,596
  
  21,571
  
  21,524
  
  18,802
  
  737
  
  730
  
  580Proved Developed
  Non-Producing
  
  97
  
  97
  
  87
  
  63
  
  63
  
  51
  
  26
  
  26
  
  20Proved
  Undeveloped
  
  1,388
  
  1,348
  
  1,065
  
  3,656
  
  3,656
  
  3,003
  
  104
  
  103
  
  84Total Proved
  Reserves
  
  65,773
  
  65,015
  
  59,748
  
  25,290
  
  25,242
  
  21,857
  
  867
  
  859
  
  684Probable
  Reserves
  
  20,342
  
  20,114
  
  17,696
  
  7,465
  
  7,446
  
  6,474
  
  284
  
  281
  
  230Total Proved
  Plus Probable Reserves
  
  86,115
  
  85,129
  
  77,444
  
  32,755
  
  32,688
  
  28,331
  
  1,151
  
  1,140
  
  914  OIL AND
  GAS RESERVESNATURAL
  GAS LIQUIDS
  
  TOTALRESERVES
  CATEGORY
  
  Company
  Interest
  
  Gross
  
  Net
  
  Company
  Interest
  
  Gross
  
  Net(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (MBOE)
  
  (MBOE)
  
  (MBOE)Proved ReservesProved Developed
  Producing
  
  11,846
  
  11,696
  
  8,254
  
  220,605
  
  218,457
  
  182,370Proved Developed
  Non-Producing
  
  517
  
  515
  
  360
  
  5,061
  
  5,059
  
  3,850Proved
  Undeveloped
  
  1,208
  
  1,200
  
  850
  
  23,502
  
  23,371
  
  18,885Total Proved
  Reserves
  
  13,571
  
  13,412
  
  9,464
  
  249,168
  
  246,887
  
  205,085Probable
  Reserves
  
  3,742
  
  3,689
  
  2,624
  
  78,898
  
  78,031
  
  65,045Total Proved
  Plus Probable Reserves
  
  17,313
  
  17,101
  
  12,088
  
  328,066
  
  324,918
  
  270,130  NET
  PRESENT VALUES OF FUTURE NET REVENUEBEFORE AND
  AFTER INCOME TAXES,RESERVES
  CATEGORY
  
  DISCOUNTED
  AT (%/YEAR)0%
  
  5%
  
  10%
  
  15%
  
  20%(in $
  millions)Proved ReservesProved Developed
  Producing
  
  3,563
  
  2,277
  
  1,727
  
  1,420
  
  1,222Proved Developed
  Non-Producing
  
  82
  
  56
  
  43
  
  35
  
  29Proved Undeveloped
  
  286
  
  172
  
  111
  
  75
  
  51Total Proved
  Reserves
  
  3,930
  
  2,505
  
  1,882
  
  1,530
  
  1,302Probable
  Reserves
  
  1,305
  
  602
  
  361
  
  250
  
  188Total Proved
  Plus Probable Reserves
  
  5,235
  
  3,107
  
  2,242
  
  1,780
  
  1,490  8 
  Summary
of Oil and Gas Reserves
and Net Present Values of Future Net Revenue
As of December 31, 2003  Constant Prices and Costs  OIL AND
  GAS RESERVESLIGHT AND
  MEDIUM OIL
  
  HEAVY
  OIL
  
  NATURAL
  GASRESERVES
  CATEGORY
  
  Company
  Interest
  
  Gross
  
  Net
  
  Company
  Interest
  
  Gross
  
  Net
  
  Company
  Interest
  
  Gross
  
  Net(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Bcf)
  
  (Bcf)
  
  (Bcf)Proved ReservesProved Developed
  Producing
  
  66,522
  
  65,805
  
  60,466
  
  22,115
  
  22,068
  
  19,202
  
  744
  
  736
  
  585Proved Developed
  Non-Producing
  
  99
  
  99
  
  88
  
  59
  
  59
  
  48
  
  26
  
  26
  
  20Proved
  Undeveloped
  
  1,398
  
  1,358
  
  1,059
  
  3,707
  
  3,707
  
  3,018
  
  104
  
  104
  
  84Total Proved
  Reserves
  
  68,019
  
  67,263
  
  61,613
  
  25,883
  
  25,836
  
  22,267
  
  874
  
  866
  
  690Probable
  Reserves
  
  20,945
  
  20,714
  
  18,156
  
  7,698
  
  7,678
  
  6,657
  
  286
  
  282
  
  231Total Proved
  Plus Probable Reserves
  
  88,964
  
  87,977
  
  79,769
  
  33,581
  
  33,514
  
  28,924
  
  1,160
  
  1,148
  
  921  OIL AND
  GAS RESERVESNATURAL
  GAS LIQUIDS
  
  TOTALRESERVES
  CATEGORY
  
  Company
  Interest
  
  Gross
  
  Net
  
  Company
  Interest
  
  Gross
  
  Net(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (MBOE)
  
  (MBOE)
  
  (MBOE)Proved ReservesProved Developed
  Producing
  
  11,986
  
  11,836
  
  8,328
  
  224,623
  
  222,376
  
  185,496Proved Developed
  Non-Producing
  
  518
  
  516
  
  360
  
  5,012
  
  5,010
  
  3,995Proved
  Undeveloped
  
  1,209
  
  1,201
  
  850
  
  23,647
  
  23,599
  
  18,927Total Proved
  Reserves
  
  13,713
  
  13,553
  
  9,538
  
  253,282
  
  250,985
  
  208,418Probable
  Reserves
  
  3,757
  
  3,705
  
  2,627
  
  80,066
  
  79,097
  
  65,940Total Proved
  Plus Probable Reserves
  
  17,470
  
  17,258
  
  12,165
  
  333,348
  
  330,082
  
  274,358  NET
  PRESENT VALUES OF FUTURE NET REVENUEBEFORE AND
  AFTER INCOME TAXES,RESERVES
  CATEGORY
  
  DISCOUNTED
  AT (%/YEAR)0%
  
  5%
  
  10%
  
  15%
  
  20%(in $
  millions)Proved ReservesProved Developed
  Producing
  
  4,035
  
  2,652
  
  2,021
  
  1,657
  
  1,417Proved Developed
  Non-Producing
  
  93
  
  66
  
  50
  
  41
  
  35Proved
  Undeveloped
  
  349
  
  221
  
  150
  
  107
  
  77Total Proved
  Reserves
  
  4,477
  
  2,938
  
  2,222
  
  1,805
  
  1,529Probable
  Reserves
  
  1,387
  
  678
  
  421
  
  297
  
  226Total Proved
  Plus Probable Reserves
  
  5,864
  
  3,616
  
  2,643
  
  2,102
  
  1,756  9 
   
 Notes:  (1)The estimated net
present values of future net revenue include the Alberta Royalty Tax Credit
based on current legislation in place on December 31, 2003.  (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 to reflect the actual price to be received.  The natural gas price adjusted, where
necessary, only for heating values and the differing costs of service applied
by various purchasers.  The natural gas
liquids prices were adjusted to reflect current prices received.  (4)The forecast price and
cost case assumes the continuance of current laws and regulations, and any
increase in selling prices also takes inflation into account.  The estimated future net revenue to be
received from the production of the reserves was based on an inflation rate of
1.5% per year, an exchange rate of Cdn$1.00=US$0.75 and the following price
forecasts supplied by Sproule:  CRUDE OIL
  
  
  NATURAL
  GAS LIQUIDSYear
  
  WTI
  Cushing
  Oklahoma
  
  Edmonton
  Par Price
  40° API
  
  Hardisty
  Heavy
  12° API
  
  Cromer
  Medium
  29.3° API
  
  NATURAL
  GAS
  AECO Gas Price
  Edmonton
  Par PricePropanes
  
  Butanes
  
  Pentanes
  Plus($US/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/MMBTU)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)2004
  
  29.63
  
  37.99
  
  23.80
  
  32.99
  
  5.81
  
  28.04
  
  31.15
  
  38.912005
  
  26.80
  
  34.24
  
  21.28
  
  29.44
  
  5.15
  
  22.56
  
  25.52
  
  35.072006
  
  25.76
  
  32.87
  
  20.80
  
  28.47
  
  4.59
  
  20.58
  
  23.28
  
  33.672007
  
  26.14
  
  33.37
  
  21.33
  
  29.07
  
  4.71
  
  20.89
  
  23.63
  
  34.172008
  
  26.53
  
  33.87
  
  21.84
  
  29.54
  
  4.80
  
  21.20
  
  23.98
  
  34.69Thereafter
  
  +1.5
  %
  +1.5
  %
  +1.5
  %
  +1.5
  %
  +1.5
  %
  +1.5
  %
  +1.5
  %
  +1.5
  %  (5)The constant price and cost case assumes the
continuance of product prices at December 31, 2003 and operating costs
projected for 2004, 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$0.77 and the following prices:  CRUDE OIL
  
  
  
  NATURAL
  GAS LIQUIDSWTI
  Cushing
  Oklahoma
  
  Edmonton
  Par
  Price
  40° API
  
  Hardisty
  Heavy
  12° API
  
  Cromer
  Medium
  29.3° API
  
  NATURAL
  GAS
  AECO Gas Price
  
  FOB Field
  GatePropanes
  
  Butanes
  
  Pentanes 
  Plus($US/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/MMBTU)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)
  
  ($Cdn/bbl)32.52
  
  40.41
  
  29.52
  
  36.68
  
  5.45
  
  27.66
  
  35.77
  
  41.58  (6)The undiscounted total future net
revenue by reserves category as of December 31, 2003, using both constant and
forecast prices and costs, is set forth below:  Reserves Category
  
  Revenue
  
  Royalties
  
  Operating
  Costs
  
  Development
  Costs
  
  Abandonment
  and Reclamation
  Costs
  
  Other
  Costs
  
  Future Net
  Revenue(in $
  millions)Constant
  Prices and CostsProved Reserves
  
  8,513
  
  1,519
  
  2,242
  
  178
  
  91
  
  6
  
  4,477Proved Plus
  Probable Reserves
  
  11,178
  
  1,997
  
  2,988
  
  213
  
  93
  
  22
  
  5,865Forecast
  Prices and CostsProved Reserves
  
  8,249
  
  1,383
  
  2,625
  
  181
  
  125
  
  5
  
  3,930Proved Plus
  Probable Reserves
  
  11,144
  
  1,860
  
  3,666
  
  216
  
  142
  
  24
  
  5,236  10 
   (7)The net present value of future net
revenue by reserves category and production group as of December 31, 2003, 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)
  
  542
  
  407Heavy Oil
  
  177
  
  128Natural Gas(b)
  
  1,503
  
  1,347Proved Plus
  Probable Reserves
  
  Light and Medium Crude Oil(a)
  
  636
  
  480Heavy Oil
  
  214
  
  158Natural Gas(b)
  
  1,793
  
  1,604  
 (a)Includes solution gas
and other by-products. (b)Includes by-products by
excludes solution gas from oil wells.  (8)The volume of gross
Proved plus Probableproduction estimated by Sproule for 2004
in preparing the estimated net present values of future net revenue is as
follows.  Product Type
  
  Aggregate
  Estimated
  2004 Production
  
  Daily
  Estimated
  2004 ProductionCrude oilLight and medium
  crude oil
  
  6,030 Mbbls
  
  16,475 bbls/dHeavy oil
  
  2,010 Mbbls
  
  5,492 bbls/dTotal crude oil
  
  8,040 Mbbls
  
  21,967 bbls/dNatural gas
  liquids
  
  1,663 Mbbls
  
  4,554 bbls/dTotal liquids
  
  9,703 Mbbls
  
  26,511 bbls/dNatural gas
  
  89,900 MMcf
  
  245,628 Mcf/dTotal
  
  24,686 MBOE
  
  67,449 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
  
  Forecast
  Prices and CostsProved Reserves
  
  Proved
  Plus
  Probable Reserves
  
  Proved
  Reserves
  
  Proved
  Plus
  Probable ReservesYear
  
  Undiscounted
  
  Discounted
  at
  10%/year
  
  Undiscounted
  
  Discounted
  at
  10%/year
  
  Undiscounted
  
  Discounted
  at
  10%/year
  
  Undiscounted
  
  Discounted
  at
  10%/year(in $
  millions)2004
  
  100
  
  95
  
  116
  
  110
  
  100
  
  95
  
  116
  
  1102005
  
  41
  
  36
  
  42
  
  37
  
  42
  
  36
  
  43
  
  372006
  
  17
  
  13
  
  25
  
  20
  
  17
  
  13
  
  26
  
  202007
  
  7
  
  5
  
  12
  
  9
  
  8
  
  5
  
  12
  
  82008
  
  6
  
  4
  
  10
  
  7
  
  6
  
  4
  
  11
  
  7Remainder
  
  7
  
  4
  
  8
  
  2
  
  8
  
  5
  
  8
  
  6Total
  
  178
  
  157
  
  213
  
  185
  
  181
  
  158
  
  216
  
  188  (10)Enerplus has approximately
7,436 MBOE of Proved plus Probable Reserves which are capable of production but
which, as of December 31, 2003, were not on production.  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.  11 
   Reconciliation of
Reserves  The following tables reconcile Enerplus oil and
natural gas reserves (on both a company interest and net basis) from December
31, 2002 to December 31, 2003, using forecast prices and costs. A significant
portion of the Technical Revisions described in the following tables are
attributable to the new methodology for determining and classifying oil and gas
reserves under NI 51-101.  Additional
information and details regarding the extent of the NI 51-101-related
revisions is contained on pages 34 to 37 of the Funds 2003 Annual Report.  Reconciliation
of Company Interest Reserves  Light and
  Medium
  Crude Oil
  
  Heavy Oil
  
  Natural
  Gas LiquidsFactors
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)December
  31, 2002
  
  78,735
  
  9,764
  
  88,499
  
  26,512
  
  6,961
  
  33,473
  
  16,036
  
  2,318
  
  18,354Acquisitions
  
  8,841
  
  1,454
  
  10,295
  
  24
  
  43
  
  67
  
  805
  
  122
  
  927Dispositions
  
  (5,226
  )
  (1,485
  )
  (6,711
  )
  (16
  )
  (292
  )
  (308
  )
  (259
  )
  (35
  )
  (294
  )Extensions
  
  372
  
  49
  
  421
  
  
  
  
  
  
  
  94
  
  
  
  94Technical
  Revisions
  
  (9,446
  )
  10,292
  
  846
  
  354
  
  520
  
  874
  
  (1,415
  )
  1,073
  
  (342
  )Discoveries
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  Economic Factors
  
  (517
  )
  (824
  )
  (1,341
  )
  408
  
  233
  
  641
  
  13
  
  264
  
  277Improved
  Recovery
  
  
  
  1,092
  
  1,092
  
  
  
  
  
  
  
  
  
  
  
  Production
  
  (6,986
  )
  
  
  (6,986
  )
  (1,992
  )
  
  
  (1,992
  )
  (1,703
  )
  
  
  (1,703
  )December 31, 2003
  
  65,773
  
  20,342
  
  86,115
  
  25,290
  
  7,465
  
  32,755
  
  13,571
  
  3,742
  
  17,313  Associated
  and
  Non-Associated Gas
  (Natural Gas)
  
  TotalFactors
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable(Bcf)
  
  (Bcf)
  
  (Bcf)
  
  (MBOE)
  
  (MBOE)
  
  (MBOE)December
  31, 2002
  
  1,002
  
  139
  
  1,141
  
  288,267
  
  42,175
  
  330,442Acquisitions
  
  88
  
  13
  
  101
  
  24,337
  
  3,769
  
  28,106Dispositions
  
  (10
  )
  (1
  )
  (11
  )
  (7,168
  )
  (2,034
  )
  (9,202
  )Extensions
  
  9
  
  3
  
  12
  
  2,025
  
  541
  
  2,566Technical
  Revisions
  
  (142
  )
  133
  
  (9
  )
  (34,230
  )
  34,275
  
  45Discoveries
  
  
  
  
  
  
  
  
  
  
  
  Economic Factors
  
  8
  
  (3
  )
  5
  
  1,273
  
  (920
  )
  353Improved
  Recovery
  
  
  
  
  
  
  
  
  
  1,092
  
  1,092Production
  
  (88
  )
  
  
  (88
  )
  (25,336
  )
  
  
  (25,336
  )December
  31, 2003
  
  867
  
  284
  
  1,151
  
  249,168
  
  78,898
  
  328,066  12 
   Reconciliation of Net Reserves  Light and
  Medium
  Crude Oil
  
  Heavy Oil
  
  Natural
  Gas LiquidsFactors
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)December
  31, 2002
  
  71,758
  
  8,505
  
  80,263
  
  23,034
  
  6,001
  
  29,035
  
  11,309
  
  1,631
  
  12,940Acquisitions
  
  7,870
  
  1,297
  
  9,167
  
  20
  
  35
  
  55
  
  572
  
  95
  
  667Dispositions
  
  (4,652
  )
  (1,342
  )
  (5,994
  )
  (13
  )
  (240
  )
  (253
  )
  (184
  )
  (28
  )
  (212
  )Extensions
  
  320
  
  60
  
  380
  
  
  
  
  
  
  
  67
  
  1
  
  68Technical
  Revisions
  
  (9,590
  )
  8,916
  
  (674
  )
  134
  
  495
  
  629
  
  (1,085
  )
  735
  
  (350
  )Discoveries
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  Economic Factors
  
  (437
  )
  (712
  )
  (1,149
  )
  343
  
  183
  
  526
  
  9
  
  190
  
  199Improved
  Recovery
  
  
  
  972
  
  972
  
  
  
  
  
  
  
  
  
  
  
  Production
  
  (5,521
  )
  
  
  (5,521
  )
  (1,661
  )
  
  
  (1,661
  )
  (1,224
  )
  
  
  (1,224
  )December
  31, 2003
  
  59,748
  
  17,696
  
  77,444
  
  21,857
  
  6,474
  
  28,331
  
  9,464
  
  2,624
  
  12,088  Associated
  and
  Non-Associated Gas
  (Natural Gas)
  
  TotalFactors
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable
  
  Proved
  
  Probable
  
  Proved
  Plus
  Probable(Bcf)
  
  (Bcf)
  
  (Bcf)
  
  (MBOE)
  
  (MBOE)
  
  (MBOE)December
  31, 2002
  
  806
  
  114
  
  920
  
  240,353
  
  35,143
  
  275,496Acquisitions
  
  70
  
  10
  
  80
  
  20,129
  
  3,229
  
  23,358Dispositions
  
  (8
  )
  (1
  )
  (9
  )
  (6,182
  )
  (1,777
  )
  (7,959
  )Extensions
  
  7
  
  3
  
  10
  
  1,554
  
  561
  
  2,115Technical
  Revisions
  
  (127
  )
  106
  
  (21
  )
  (31,694
  )
  27,572
  
  (4,122
  )Discoveries
  
  
  
  
  
  
  
  
  
  
  
  Economic Factors
  
  6
  
  (2
  )
  4
  
  915
  
  (655
  )
  260Improved
  Recovery
  
  
  
  
  
  
  
  
  
  972
  
  972Production
  
  (70
  )
  
  
  (70
  )
  (19,990
  )
  
  
  (19,990
  )December
  31, 2003
  
  684
  
  230
  
  914
  
  205,085
  
  65,045
  
  270,130  13 
   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 Proved Reserves from December 31, 2002 to December 31, 2003 using
constant prices and costs and discounted at 10% per year.  Period and Factor
  
  Year Ended
  December 31, 2003(in $
  millions)Estimated Future
  Net Revenue at Beginning of Year
  
  $
  3,032.7Sales and
  Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and
  Royalties
  
  (453.8
  )Net Change in
  Prices, Production Costs and Royalties Related to Future Production
  
  (409.8
  )Changes in
  Previously Estimated Development Costs Incurred During the Period
  
  (70.2
  )Changes in
  Estimated Future Development Costs
  
  22.0Extensions and Improved
  Recovery
  
  16.6Discoveries
  
  Acquisitions of
  Reserves
  
  214.6Dispositions of
  Reserves
  
  (65.9
  )Net Change
  Resulting from Revisions in Quantity Estimates
  
  (337.9
  )Accretion of
  Discount
  
  273.4Net Change in
  Income Taxes
  
  N/AEstimated Future
  Net Revenue at End of Year
  
  $
  2,221.7  Historical
Undeveloped Reserves  The following table discloses the volumes of
Undeveloped Reserves of Enerplus as at December 31, 2003 that were first
attributed in 2003.  Proved
  Undeveloped Reserves
  
  Probable
  Undeveloped ReservesCrude Oil
  
  
  
  
  
  
  
  Crude OilYear
  
  Heavy
  
  Light and
  Medium
  
  NGLs
  
  Natural
  Gas
  
  Total
  
  Heavy
  
  Light and
  Medium
  
  NGLs
  
  Natural
  Gas
  
  Total(Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Bcf)
  
  (MBOE)
  
  (Mbbls)
  
  (Mbbls)
  
  (Mbbls)
  
  (Bcf)
  
  (MBOE)2003
  
  950
  
  320
  
  35
  
  27.5
  
  5,888
  
  74
  
  263
  
  80
  
  33.9
  
  6,067  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.  14 
   OPERATIONAL INFORMATION  Description of Principal Properties  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 2003. All
production information represents Enerplus company interest in these
properties before deduction of royalty interests owned by others. All references
to reserve volumes are based upon the estimated volumes contained in the
Sproule Report (using forecast prices and costs) applicable to Enerplus  company interest reserves, before deduction
of any royalties.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 Alberta, British
Columbia, 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, 2003 from
Enerplus properties consisted of approximately 42% crude oil and NGLs and 58%
natural gas on a BOE basis.  Enerplus
2003 production was comprised of average daily production 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, an increase of 11% when compared to the previous year. During
2002, production consisted of 23,288 bbls/d of crude oil, 4,410 bbls/d of NGLs
and 210.5 MMcf/d of natural gas for a total of 62,784 BOE/d. As at December 31,
2003, the oil and natural gas property interests held by Enerplus were
estimated to contain Proved plus Probable Reserves of 136.2 MMbbls of crude oil
and NGLs and 1,151 Bcf of natural gas for a total of 328.1 MMBOE.  See Oil and Natural Gas Reserves.  During 2002, Enerplus reorganized from a functionally
aligned organization into a business unit structure, with four geographically
distinct high working interest Enerplus-operated business units which accounted
for approximately 60% of 2003 average daily production, and a joint venture
business unit which accounted for approximately 40% of 2003 daily production.
This restructuring enabled Enerplus to better focus its activities and is
expected to improve 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.  Joint Venture Business Unit  The Joint Venture Business Unit accounts for
approximately 40% of Enerplus 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, more
technically complex projects than Enerplus might pursue on its own.  Production from this business unit for the year ended
December 31, 2003 averaged 6,110 bbls/d of crude oil, 2,813 bbls/d of NGLs and
113.0 MMcf/d of natural gas for a total of 27,764 BOE/d. As at January 1, 2004,
the Joint Venture Business Units property interests contained 119.4 MMBOE of
Proved plus Probable Reserves consisting of 36.9 MMbbls of crude oil and NGLs
and 495.1 Bcf of natural gas.  The key properties within this business unit include
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; interests in the sweet, liquids rich
gas play in the Central Alberta Pine Creek area operated by Burlington
Resources Canada Ltd. and Suncor Energy Inc. and interests in the Mount
Benjamin property operated by Petro-Canada. The Mount Benjamin property is a
deep foothills natural gas property where, during 2003, efforts were put into
optimizing surface production facilities to maximize production from the area.
Since acquiring this property in 2000, a total of five wells have been drilled
with a 100% success rate, increasing production in a prolific natural gas area
where significant production declines are more typical.  15 
   The Joint Venture Business Unit is also participating
in a unique nitrogen injection pilot in the Turner Valley area outside of
Calgary. This project, operated by Talisman Energy Inc., began operation in September
of 2002 and to date, initial positive pressure responses had been observed.
Although in a very early stage, if successful, it will lead to a full scale
development program designed to recover an additional 3% to 10% of the
estimated one billion barrels of crude oil reserves in place (approximately 1.5
to 5.0 million barrels of crude oil net to Enerplus).  During 2003, the acquisition of PCC added
approximately 3,000 BOE/d of production to the Joint Venture Business Unit.
Most of this production is generated from the greater Hanlan area which is
comprised of deep, sour but high impact natural gas plays. This acquisition
also brought significant development opportunities to Enerplus. Development
capital relating to the PCC properties amounted to $10 million in 2003.  Major production facilities within this business unit
include:  a 6% interest in the Elmworth
Gas Plant; a 3% interest in Wapiti Gas Plants; a 10% interest in the Progress
Gas Plant; an 8.5% in the Hanlan-Robb Sour Gas Plant; an 8% interest in a
sweetening and absorption facility at Minnehik Buck Lake; a 2% interest in the
Ram River sweetening and refrigeration facility; and a 22% interest in an
emulsion treating and water disposal facility at Hayter.  Enerplus expects 2004 capital expenditures for this
partner-operated business unit to remain consistent with 2003, with
approximately 85% of Enerplus joint venture business unit capital budget
focused on natural gas-weighted projects and 15% on oil-weighted projects.
Additionally, as a continuation of its strategic investments in the Athabasca
Oil Sands fairway, Enerplus will continue to fund the initial phases of the
Joslyn Creek SAGD development project and expects to spend up to $6.0 million
on this project in 2004, with initial production expected in mid-2004.  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 200 operated shallow natural gas
wells drilled in 2003. In addition, Enerplus successfully tested natural gas
from coal in its Hanna and Bantry fields. 
The Freda Lake Ratcliffe Unit, in which Enerplus acquired additional
working interests in 2003, is also in this business unit, and along with the
Medicine Hat Glauconitic C Pool contributes significant crude oil production.  Production from this business unit for the year ended
December 31, 2003 averaged 3,838 bbls/d of crude oil, 36 bbls/d of NGLs and
59.9 MMcf/d of natural gas for a total of 13,849 BOE/d. As at January 1, 2004,
the Southern Business Units property interests contained 91.4 MMBOE of Proved
plus Probable Reserves consisting of 22.7 MMbbls of crude oil and NGLs and
412.2 Bcf of natural gas.  The Southern Business Units key natural gas producing
properties include Hanna Garden Plains, Bantry, Verger, Countess and Medicine
Hat Sun Valley, all of which have a large contiguous land base, pipeline
infrastructure and major compression and dehydration facilities. The major
crude producing property for this business unit is the previously mentioned
Medicine Hat Glauconitic C Pool, which is under a waterflood recovery
program. Various other minor properties contribute to the remainder of this
business units production, including the Heward, Saskatchewan area, where some
significant emulsion treating and water disposal facilities are located.  Enerplus plans to continue shallow natural gas
development drilling in 2004, including higher density drilling within existing
producing areas. Confirmation of the viability of the increased density of well
spacing will add further development opportunities in the future. Delineation
of the natural gas bearing coal beds will continue in 2004 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 Freda Lake Ratcliffe pools.  16 
   Eastern Business Unit  The Eastern Business Unit focuses on waterflood
development projects and encompasses operated properties and lands in eastern
Alberta and western Saskatchewan along the provincial border.  This business unit is predominantly oil
weighted with properties producing light sweet, medium quality and conventional
heavy oil. The majority of these oil properties are under 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, 2003 averaged 9,258 bbls/d of crude oil, 189 bbls/d of NGLs and
11.4 MMcf/d of natural gas for a total of 11,347 BOE/d. As at January 1, 2004,
the Eastern Business Units property interests contained 52.4 MMBOE of Proved
plus Probable Reserves consisting of 41.1 MMbbls of crude oil and NGLs and 63.1
Bcf of natural gas.  The key properties within this business unit include
Joarcam, Giltedge and Gleneath. Significant crude oil production installations
for emulsion treating and water disposal or injection are found at Joarcam,
Giltedge, Gleneath, Silver Heights, Shorncliff, newly acquired Shorncliff East,
Cadogan, Kessler, David, Neutral Hills and Chauvin. In addition, Joarcam also
has major facilities for natural gas compression, dehydration and processing.  Joarcam is Enerplus 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 2003 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 2004 will build on Enerplus historical success and
continue to focus on improving and expanding its existing waterfloods to
increase production and recovery. Divestments of minor interests and
acquisitions in Enerplus core properties will increase the operational focus
in the area.  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, shallow decline production profiles while gas is
produced from high deliverability, large reserve natural gas pools.  Production from this business unit for the year ended
December 31, 2003 averaged 2,924 bbls/d of crude oil, 1,192 bbls/d of NGLs and
34.2 MMcf/d of natural gas for a total of 9,822 BOE/d. As at January 1, 2004,
the Central Business Units property interests contained 47.7 MMBOE of Proved
plus Probable Reserves consisting of 28.0 MMbbls of crude oil and NGLs and
118.4 Bcf of natural gas.  The Central Business Units key producing property for
2003 was Pembina 5 Way, primarily a 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 2003 was targeted at
shallow natural gas drilling in the Sylvan Lake and Medicine River core
areas.  An initiative to further exploit
the shallow natural gas potential in additional properties within the Central
Business Unit commenced in the latter half of 2003.  The focus of this business units investment activity
in 2004 will be to further develop its shallow natural gas program, including
re-completions in potential uphole natural gas-bearing formations overlying oil
production in the  17 
   Pembina area. 
Enerplus also intends to re-evaluate continued infill drilling and
recompletion initiatives to maintain light crude oil production in this region.  Northern Business Unit  The Northern Business Unit is a less developed region
that encompasses all Enerplus-operated lands and production in northwest
Alberta and northeast British Columbia. 
This business unit provides exposure to both light crude oil and liquids
rich natural gas through a variety of Triassic to Cretaceous age reservoirs and
tends to offer high impact potential per well, although there are fewer
drilling locations than in other business units. The Northern Business Units
key properties are two adjacent areas, Valhalla and Progress, both of which
produce crude oil and natural gas. Other less significant properties include
Clarke Lake, La Glace and Desmarais.  Production from this business unit for the year ended
December 31, 2003 averaged 2,468 bbls/d of crude oil, 436 bbls/d of NGLs and
22.4 MMcf/d of natural gas for a total of 6,634 BOE/d. As at January 1, 2004,
the Northern Business Units property interests contained 17.2 MMBOE of Proved
plus Probable Reserves consisting of 6.8 MMbbls of crude oil and NGLs and 62.2
Bcf of natural gas.  During 2003, development activities were primarily
directed to improving light crude oil production at Valhalla and Progress while
optimizing natural gas production at Progress, Bonanza and Valhalla through
facility upgrades and development drilling. Since 1996, and particularly in
recent years, Enerplus has steadily increased production from the Valhalla
property through development efforts. In 2003, five wells were drilled in the
Progress field to extend the Halfway B pool and enhance recovery in the
Boundary pool, and two wells were drilled in the Valhalla Halfway J pool to
enhance crude oil recovery and optimize the production from this pool.
Facilities in the Progress areas were also enhanced and natural gas production
was re-routed to the Progress Anadarko Plant to utilize Enerplus working
interest to handle the sour natural gas volumes. In late 2003, non-core
properties in the north central Alberta area surrounding Slave Lake were
divested to enable the business unit to concentrate on core areas.  Development activities for 2004 will target additional
development in Progress Halfway to further enhance production and recoverable
reserves. Enerplus intends to lever its existing positions of undeveloped
acreage and extensive seismic inventory, along with a review of non-productive
wellbores, to further enhance this business units development opportunities
for value creation in 2004 and into the future.  Summary of Production Locations  During the year ended December 31, 2003, on a BOE basis, 88% of
Enerplus production was derived from Alberta, 8% from Saskatchewan and 4% from
British Columbia. 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, 2003:  18 
   ProductCrude OilBusiness Unit and Property
  
  Heavy
  
  Light and
  Medium
  
  NGLs
  
  Natural
  Gas
  
  Total(bbls/d)
  
  (bbls/d)
  
  (bbls/d)
  
  (Mcf/d)
  
  (BOE/d)Joint
  Venture Business UnitMount Benjamin
  
  
  
  
  
  17
  
  12,984
  
  2,181Elmworth
  
  
  
  
  
  352
  
  6,471
  
  1,431Pine Creek
  
  
  
  1
  
  290
  
  5,960
  
  1,285Ferrier
  
  
  
  60
  
  258
  
  4,520
  
  1,072South Wapiti
  
  
  
  
  
  201
  
  4,096
  
  883Hanlan
  
  
  
  
  
  4
  
  5,268
  
  882Rigel
  
  
  
  742
  
  7
  
  208
  
  783Hayter
  
  744
  
  
  
  1
  
  26
  
  748Mountain Park
  
  
  
  
  
  6
  
  4,186
  
  703Progress
  
  
  
  46
  
  71
  
  3,422
  
  687Verger
  
  
  
  
  
  
  
  3,588
  
  598Other
  
  636
  
  3,882
  
  1,606
  
  62,314
  
  16,510Total
  
  1,380
  
  4,730
  
  2,813
  
  113,043
  
  27,764Southern
  Business UnitBantry
  
  
  
  2
  
  
  
  14,436
  
  2,408Hanna Garden
  
  
  
  2
  
  1
  
  12,708
  
  2,121Medicine Hat
  
  1,667
  
  
  
  
  
  962
  
  1,827Verger
  
  
  
  6
  
  
  
  7,998
  
  1,339Medicine Hat Sun
  Valley
  
  
  
  2
  
  
  
  6,588
  
  1,100Other
  
  9
  
  2,149
  
  35
  
  17,162
  
  5,053Total
  
  1,676
  
  2,161
  
  36
  
  59,854
  
  13,849Eastern
  Business UnitJoarcam
  
  
  
  2,152
  
  145
  
  6,066
  
  3,308Giltedge
  
  1,852
  
  
  
  
  
  399
  
  1,919Gleneath
  
  
  
  1,117
  
  22
  
  444
  
  1,213Other
  
  1,231
  
  2,906
  
  22
  
  4,489
  
  4,907Total
  
  3,083
  
  6,175
  
  189
  
  11,399
  
  11,347Central
  Business UnitPembina 5 Way
  
  
  
  2,156
  
  126
  
  1,619
  
  2,553Sylvan Lake
  
  
  
  405
  
  239
  
  4,010
  
  1,313Ferrier
  
  
  
  18
  
  187
  
  4,314
  
  924Pine Creek
  
  
  
  7
  
  178
  
  4,354
  
  910Other
  
  
  
  338
  
  462
  
  19,937
  
  4,122Total
  
  
  
  2,924
  
  1,192
  
  34,234
  
  9,822Northern
  Business UnitValhalla
  
  
  
  312
  
  98
  
  8,205
  
  1,777Progress
  
  
  
  615
  
  29
  
  2,183
  
  1,007Other
  
  
  
  1,542
  
  309
  
  11,988
  
  3,849Total
  
  
  
  2,468
  
  436
  
  22,377
  
  6,634TOTAL
  
  6,139
  
  18,458
  
  4,666
  
  240,907
  
  69,414  19 
   Oil
and Natural Gas Wells and Unproved Properties  The following table summarizes, as at December 31,
2003, 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
  PropertiesOil
  
  Natural
  Gas
  
  Oil
  
  Natural
  Gas
  
  (thousand
  of acres)Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  NetAlberta
  
  4,203
  
  1,476.3
  
  4,684
  
  2,358.4
  
  853
  
  311.4
  
  286
  
  105.8
  
  696.3
  
  277.9Saskatchewan
  
  2,948
  
  579.6
  
  359
  
  261.1
  
  278
  
  48.0
  
  5
  
  0.9
  
  35.9
  
  35.6British Columbia
  
  289
  
  36.6
  
  116
  
  27.5
  
  62
  
  9.6
  
  53
  
  15.4
  
  77.1
  
  25.9Manitoba
  
  28
  
  28.0
  
  
  
  
  
  
  
  
  
  
  
  
  
  0.6
  
  0.6Total
  
  7,468
  
  2,120.5
  
  5,159
  
  2,647.0
  
  1,193
  
  369.0
  
  344
  
  122.1
  
  809.9
  
  340.0  Enerplus expects its rights to explore, develop and
exploit on approximately 70,000net acres to ordinarily expire prior to
December 31, 2004.  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.  Development
Activities  The primary operational focus of Enerplus is to pursue
attractive risk/return growth opportunities through the development of existing
properties, the monetization of Enerplus exploratory lands and the acquisition
of new properties.  Higher risk
exploration plays are generally farmed out, sold, or exchanged for other
interests with more attractive risk/return characteristics.  Enerplus will 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 2003, Enerplus participated in the drilling of543
gross wells (294 net wells) with a 98% net well success rate.  The majority of Enerplus 2003 wells were
drilled in southern Alberta and southwest Saskatchewan in the operated shallow
natural gas regions of Medicine Hat, Verger, Countess, Hanna Garden, Bantry and
Fox Valley. Enerplus also participated in the drilling of an increased number
of non-operated wells in the Deep Basin areas and foothills natural gas
regions. The following table summarizes the number and type of wells that
Enerplus drilled or participated in the drillingoffor the year ended December
31, 2003.Enerplus did not participate in
drilling any exploratory wells in any such period.  Number of
  WellsCategory of Well
  
  Gross
  
  NetCrude oil wells
  
  92
  
  30.1Natural gas
  wells
  
  441
  
  259.1Dry and
  abandoned wells
  
  10
  
  4.6543
  
  293.8Service wells
  
  
  
  Total
  
  543
  
  293.8
  Enerplus currently intends to focus its development
activities in the Western Canadian Sedimentary Basin.Enerplus development
activities are typically funded through debt which is subsequently repaid
through the issuance of Trust Units and internally generated cash flow. See
Additional Operational Information  Acquisition and Development Activities
below.  20 
   Quarterly
Production History  The following table sets forth Enerplus average daily
production volumes, on a company interest basis,for each fiscal quarter in
2003 and for the entire year.  Year Ended
  December 31, 2003First
  Quarter
  
  Second
  Quarter
  
  Third
  Quarter
  
  Fourth
  Quarter
  
  Total for
  YearCrude oilLight and medium
  oil (bbls/d)
  
  18,446
  
  19,431
  
  17,483
  
  18,480
  
  18,458Heavy oil
  (bbls/d)
  
  6,054
  
  6,075
  
  6,427
  
  5,997
  
  6,139Total crude oil
  (bbls/d)
  
  24,500
  
  25,506
  
  23,910
  
  24,477
  
  24,597Natural gas
  liquids (bbls/d)
  
  4,574
  
  4,526
  
  4,795
  
  4,768
  
  4,666Total liquids
  (bbls/d)
  
  29,074
  
  30,032
  
  28,705
  
  29,245
  
  29,263Natural gas
  (Mcf/d)
  
  232,911
  
  243,540
  
  243,458
  
  243,573
  
  240,907Total (BOE/d)
  
  67,893
  
  70,622
  
  69,281
  
  69,841
  
  69,414  Quarterly
Netback History  The following tables set forth Enerplus average
netbacks received for each fiscal quarter in 2003 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, 2003First
  Quarter
  
  Second
  Quarter
  
  Third
  Quarter
  
  Fourth
  Quarter
  
  Total for
  YearSales price
  
  $
  46.40
  
  $
  36.77
  
  $
  37.72
  
  $
  33.94
  
  $
  38.66Royalties
  
  (6.80
  )
  (5.35
  )
  (6.21
  )
  (6.02
  )
  (6.08
  )Production
  costs(1)
  
  (10.37
  )
  (9.30
  )
  (11.89
  )
  (13.04
  )
  (11.13
  )Netback
  
  $
  29.23
  
  $
  22.12
  
  $
  19.62
  
  $
  14.88
  
  $
  21.45  Heavy Oil ($ per bbl)  Year Ended
  December 31, 2003First
  Quarter
  
  Second
  Quarter
  
  Third
  Quarter
  
  Fourth
  Quarter
  
  Total for
  YearSales price
  
  $
  35.23
  
  $
  27.63
  
  $
  27.44
  
  $
  24.32
  
  $
  28.61Royalties
  
  (6.44
  )
  (5.09
  )
  (5.29
  )
  (4.65
  )
  (5.37
  )Production
  costs(1)
  
  (6.52
  )
  (8.86
  )
  (7.89
  )
  (10.55
  )
  (8.44
  )Netback
  
  $
  22.27
  
  $
  13.68
  
  $
  14.26
  
  $
  9.12
  
  $
  14.80  Natural Gas Liquids ($ per bbl)  Year Ended
  December 31, 2003First
  Quarter
  
  Second
  Quarter
  
  Third
  Quarter
  
  Fourth
  Quarter
  
  Total for
  YearSales price
  
  $
  36.34
  
  $
  31.76
  
  $
  30.04
  
  $
  35.66
  
  $
  33.43Royalties
  
  (9.84
  )
  (7.23
  )
  (7.57
  )
  (7.61
  )
  (8.05
  )Production
  costs(1)
  
  
  
  
  
  
  
  
  
  Netback
  
  $
  26.50
  
  $
  24.53
  
  $
  22.47
  
  $
  28.05
  
  $
  25.38  21 
   Natural Gas ($ per Mcf)  Year Ended
  December 31, 2003First
  Quarter
  
  Second
  Quarter
  
  Third
  Quarter
  
  Fourth
  Quarter
  
  Total for
  YearSales price
  
  $
  8.10
  
  $
  6.32
  
  $
  5.78
  
  $
  5.10
  
  $
  6.30Royalties
  
  (1.85
  )
  (1.43
  )
  (1.25
  )
  (1.12
  )
  (1.41
  )Production
  costs(1)
  
  (0.72
  )
  (0.88
  )
  (0.85
  )
  (1.03
  )
  (0.87
  )Netback
  
  $
  5.53
  
  $
  4.01
  
  $
  3.68
  
  $
  2.95
  
  $
  4.02  Total ($ per BOE)  Year Ended
  December 31, 2003First
  Quarter
  
  Second
  Quarter
  
  Third
  Quarter
  
  Fourth
  Quarter
  
  Total for
  YearSales price
  
  $
  46.01
  
  $
  36.33
  
  $
  34.47
  
  $
  31.36
  
  $
  36.94Royalties
  
  (9.45
  )
  (7.32
  )
  (6.98
  )
  (6.42
  )
  (7.51
  )Production
  costs(1)
  
  (5.86
  )
  (6.34
  )
  (6.70
  )
  (7.98
  )
  (6.73
  )Netback
  
  $
  30.70
  
  $
  22.67
  
  $
  20.79
  
  $
  16.96
  
  $
  22.70  
 Note: (1)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,
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
$234 million on an undiscounted basis and $35 million discounted at 10%.
Additionally, of this amount, the calculations of future net revenue in the tables
under Oil and Natural Gas Reserves above have excluded approximately $93
million on an undiscounted basis and $14 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 $21 million on an undiscounted basis
and $17.3 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, 2003.  See Note 5 to the Funds audited financial
statements for the year ended December 31, 2003. Under Enerplus current structure
and existing tax legislation, annual taxable income is transferred from its
operating entities to the Fund through interest and royalty payments. The Fund,
in turn, allocates all of its taxable income to unitholders through payment of
cash distributions and therefore no cash income tax is incurred in the Fund or
its operating subsidiaries.  Costs Incurred  In the financial year ended December 31, 2003,
Enerplus expended a total of $225.3 million on corporate and property
acquisitions, as well as $157.7 million for development and facilities costs.  22 
   Marketing
Arrangements and Forward Contracts  Crude Oil and NGLs  Enerplus crude oil and NGLs production is marketed to
a diverse portfolio of intermediaries and end users on 30 day continuously
renewing contracts whose terms fluctuate with monthly spot market prices.  Enerplus received an average price before
hedging of $36.15/bbl for its crude oil and $33.43/bbl for its NGLs for the
year ended December 31, 2003, compared to $34.37/bbl for crude oil and
$25.68/bbl for NGLs for the year ended December 31, 2002.  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
2003, 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 2003 revenues attributable to
natural gas, before hedging, was 59% compared to 47% in 2002, notwithstanding
that natural gas represented over 55% of Enerplus total production in both
2003 and 2002. The average price received by Enerplus, before hedging, for its
natural gas in 2003 was $6.30/Mcf compared to $3.87/Mcf in the year ended
December 31, 2002.  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 8
to the Funds audited annual consolidated financial statements for the year
ended December 31, 2003 and under the heading Pricing and Price Risk
Management in the Funds managements discussion and analysis for the year
ended December 31, 2003 which is contained on pages56 to 58 of the Funds 2003
Annual Report, both of which are incorporated herein by reference.  Environment, Health and
Safety  Enerplus places a high priority on protecting the
environment and on the health and safety of its employees, contractors and the
public.  Enerplus recognizes the value
of maintaining superior environment, health and safety (EHS) standards and
actively manages programs to support and measure efforts for further
improvement.  Enerplus monitors the key industry benchmarks of
recordable and lost time injuries for employees and contractors.  Enerplus results compare favourably to
industry data as its employees have not experienced a loss time accident since
2000 and have consistently outperformed the employee recordable injury index as
measured against benchmark data provided by the Canadian Association of
Petroleum Producers (CAPP).  The
Enerplus EHS Management System includes ongoing assessments designed to support
top tier performance and continuous improvement as demonstrated by the following
initiatives:  23 
   Enerplus
achieved a 94% rating from a third party audit conducted on its Certificate of
Recognition in the Partnership Program with Alberta Human Resources and
Employment and the Workers Compensation Board;  Enerplus
continues to participate at a Platinum Level, the highest level attainable, in
the Environmental Health and Safety Stewardship Program initiated by CAPP;  an
internal EHS Steering Committee was formed, comprised of executives, managers
and EHS staff, to address environmental, health and safety standards and
policies.  The committees functions
include enhancements to programs to ensure hazardous tasks are carried out
safely, responsibly and effectively; and  as
part of a Corrosion Integrity Management Program, Enerplus continues to provide
inspection and upgrading of its production infrastructure to minimize potential
environmental and financial impacts. 
During 2003 approximately 2,000 kilometers (representing approximately
43%) of Enerplus pipelines were flow modeled and risk assessed, 410 (25%) of
its tanks were inspected or leak tested, and 100% of the required pressure
vessels inspections were completed. Enerplus also successfully achieved the
Alberta Boiler Safety Association external three-year audit renewal.  Environmental, health and safety risks influence
Enerplus workforce as well as its operating and capital costs. In addition,
the oil and gas industry is subject to numerous related laws and
regulations.  See Industry Conditions 
Environmental Regulation.  Enerplus
mitigates these risks through the following measures:  developing
and adhering to standards, procedures and practices that protect the
environment, and the health and safety of Enerplus employees, contractors and
the public, that meet or exceed the government regulations and requirements;  health
and safety inspections and audits are conducted regularly to ensure hazards are
identified and controlled. Enerplus conducts both internal and third party site
inspections at selected facilities, construction and drilling projects each
year;  all
reported incidents are reviewed to understand the underlying causes in order to
prevent reoccurrence and raise safety awareness of employees and contractors;  environmental
inspections are conducted regularly to identify environmental liabilities and
correct Enerplus well site and facility reclamation and abandonment program;  ensuring
that emergency response plans meet all regulatory requirements and are in place
and practiced regularly to prevent and deal with incidents quickly and
effectively; and  conducting
thorough due diligence investigations on potential acquisitions to ensure that
environmental liabilities and safety concerns are identified and properly
quantified.  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 4% of the total development expenditures incurred by
Enerplus in 2003.  Since the
environmental standards and regulations to which Enerplus is subject (including
the Kyoto Protocol) generally apply to all participants in the oil and gas
industry, it is not anticipated that Enerplus competitive position within the
industry, particularly among issuers holding properties with similar
characteristics, will be adversely affected. 
See Industry Conditions - Environmental Regulation and Risk Factors.  24 
   Additional
Operational Information  Management Policies  The board of directors of EnerMark oversees the
business and affairs of Enerplus. It supervises Enerplus management as it
manages and administers the business and operations of Enerplus in accordance
with general policies and principles established by the EnerMark
directors.  The strategies employed and
activities undertaken by the EnerMark directors and Enerplus management are
directed towards maximizing distributable income to the unitholders while at
the same time striving for long-term growth in the value of the assets of
Enerplus. These two objectives are fundamental to the operation of Enerplus and
are balanced to maximize benefit to the unitholders. Enerplus utilizes its
extensive experience and employs prudent oil and gas business practices to
increase the value of the assets of Enerplus through the acquisition and
development of producing oil and gas properties.  Acquisition and Development
Activities  The primary operational focus of Enerplus is to pursue
growth opportunities through the acquisition and development of mature,
lower-risk, long-life oil and natural gas properties.  Since Enerplus does not generally engage in exploration
activities, it relies primarily upon acquisitions to both replenish and add to
its oil and natural gas reserves. 
Enerplus acquires properties and assets which are consistent with the
guidelines for acquisitions which may be established from time to time by the
board of directors of EnerMark. Any conventional oil and gas asset or property acquisition
(or disposition) with a value of greater than $25 million requires the approval
of the directors of EnerMark.  In
pursuing acquisitions, Enerplus employs a focused and disciplined strategy to
ensure that the reserves being considered are a strategic fit with its existing
portfolio of properties.  Enerplus has
typically funded its acquisitions through either borrowings from its existing
credit facility or the direct issuance of Trust Units.  Borrowings are subsequently repaid through
the issuance of additional Trust Units or from internally-generated cash
flows.  This strategy provides Enerplus
with the flexibility to respond to acquisition opportunities on a timely basis.  To the extent its acquisitions include higher risk
exploration opportunities, Enerplus enters into farmout or swap agreements
under which an exploration and production company will explore and drill these
opportunities on Enerplus behalf, generally at no cost to Enerplus, in
exchange for a portion of Enerplus interests in the property.  Other exploration properties may be sold to
allow Enerplus to focus on more attractive risk/return development activities,
as discussed elsewhere in this Annual Information Form.  Enerplus undertakes attractive risk/return development
activities to mitigate declines in total production, upgrade its reserves and
extend the useful lives of many of its properties.  Development activities are particularly important to Enerplus
during periods when there are a limited number of attractive acquisition opportunities.  Enerplus development activities provide a
lower-risk, less capital intensive alternative for increasing production
volumes than do traditional exploration activities.  Enerplus development activities are typically funded through
debt which is subsequently repaid through the issuance of Trust Units and
internally generated cash flow.  Insurance  Enerplus carries insurance coverage to protect its
assets at or above the standards typical within the oil and natural gas
industry.  Coverages are determined and
placed by Enerplus after considering the perceived risk of loss, limit of
coverage determined appropriate and the cost of coverages.  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.  Borrowing  The Fund may, provided that the approval of the board
of directors of EnerMark has been obtained, 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.  Details of EnerMarks debt
arrangements are  25 
   contained in Note 3 to the Funds audited annual
consolidated financial statements for the year ended December 31, 2003 and
under the heading Liquidity and Capital Resources in Enerplus management
discussion and analysis, contained on page 66 of the Funds 2003 Annual Report,
each of which is incorporated herein by reference.  The indebtedness of Enerplus to its lenders and senior
noteholders ranks senior and is in priority to the royalty, interest 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.  Records  Enerplus keeps those books and records as are
necessary for the proper recording of the business transactions of the
Fund.  These records are, as nearly as
practicable, in accordance with those required to be maintained by a
distributing corporation incorporated under the Business Corporations Act
(Alberta). Unitholders at all times have access to these records to the same
extent as though they were shareholders of such a corporation.  All such records are kept by Enerplus at its
office in Calgary, Alberta.  Personnel  As at December 31, 2003, Enerplus employed a total of
456 persons.  26 
   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  27 
   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.  28 
   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.  Accordingly, the Trust Indenture
provides that, from time to time, EnerMark may restrict the number of Trust
Units owned by non-residents and take all necessary steps to monitor the
ownership of the Trust Units such that the Fund maintains the status of a unit
trust and mutual fund trust for the purposes of the Tax Act.  The Trust Indenture also provides that, if
at any time EnerMark becomes aware that the  29 
   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 fideexercise 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  Recent Developments  Non-Resident Ownership, Mutual Fund
Trust Status and Impact of 2004 Canadian Federal Governmental Budget Proposals
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 EOG.  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 EOG
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 the Trustee, may declare payable to the unitholders
on a pro rata basis all or any part of the distributable income and  30 
   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  31 
   (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.  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 specieto 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.  32 
   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  33 
   (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 EOG, respectively, on the production from
their oil and natural gas properties; (ii) interest and principal payments
on unsecured, subordinated debt issued to the Fund by EnerMark; and
(iii) dividend and distribution payments received by the Fund from
EnerMark and certain other operating subsidiaries of the Fund.  Outlined below is a description of the
royalties granted by EnerMark, ERC and EOG 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 EOG 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 EOG 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 EOG 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 EOG 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 EOG 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 EOG 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 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  34 
   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
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
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 and dividend payments from EnerMark,
ERC and EOG to the Fund, and the related cash distributions from the Fund to
unitholders, may be adversely affect 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 on pages 44 to
49 of the Funds 2003 Annual Report and under the heading Statement of
Corporate Governance Practices in the Funds information circular and proxy
statement dated March 17, 2004.  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 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.  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.  35 
   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
determines both the extent to which cash flow will be allocated to the
repayment of debt, as well as the amount of cash flow to apply to capital
expenditures.  The board of directors of
EnerMark regularly evaluates the Funds distribution payout with respect to
forecast cash flows, debt levels and capital expenditures plans.  In the past, the level of cash retained for
debt repayment has typically varied between 10% and 25% of the total annual
cash flow.  For the year ended December
31, 2003, approximately 19% of the cash available for distribution was retained
for debt repayment (approximately 8% after costs associated with the management
internalization of EGEM).  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 Units will be affected by the number of outstanding Trust Units.  The following cash distributions have been paid by Enerplus to its
unitholders since the beginning of 2002:  Month of Record
  and Payment Date
  
  Cash
  Distribution Per Trust Unit2004
  
  2003
  
  2002January(1)
  
  $
  0.35
  
  $
  0.30
  
  $
  0.30February
  
  $
  0.35
  
  $
  0.32
  
  $
  0.25March
  
  $
  0.35
  
  $
  0.35
  
  $
  0.20April
  
  $
  0.35
  
  $
  0.35
  
  $
  0.20May
  
  N/A
  
  $
  0.37
  
  $
  0.28June
  
  N/A
  
  $
  0.37
  
  $
  0.28July
  
  N/A
  
  $
  0.37
  
  $
  0.28August
  
  N/A
  
  $
  0.37
  
  $
  0.28September
  
  N/A
  
  $
  0.37
  
  $
  0.28October
  
  N/A
  
  $
  0.37
  
  $
  0.30November
  
  N/A
  
  $
  0.35
  
  $
  0.30December
  
  N/A
  
  $
  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.  36 
   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.  37 
   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  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 form pools discovered
after September 30, 1992).  The royalty
rate on old oil is between 10% and 35%, for new oil it is between 10% and 30%,
and for third tier oil it is between 10% and 25%.  The royalty payable to the Alberta government in
respect of natural gas is determined by a sliding scale based on a reference
price (which is the greater of the amount obtained by the producer and a
prescribed minimum price), the type of natural gas, the quantity produced in a
given month and the vintage of the natural gas. The vintage of natural gas is
based on various criteria set out in the regulations, but is generally
determined based on when the natural gas pools were discovered and natural gas
from such pools was recovered.  As an
incentive for the production and marketing of natural gas which may have been
flared, the royalty rate on natural gas produced in association with oil is
less than non-associated natural gas. The royalty payable on natural gas varies
between 15% and 30%, in the case of new natural gas, and between 15% and 35%,
in the case of old natural gas. Natural gas produced from qualifying
exploratory natural gas wells spudded or deepened after July 31, 1985 and
before June 1, 1988 is eligible for a royalty exemption for a period of 12
months, up to a prescribed maximum amount. 
Natural gas produced from qualifying intervals in eligible natural gas
wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty
exemption, the amount of which depends on the depth of the well.  38 
   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.  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  39 
   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.  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 Environmental
Protection and Enhancement Act(Alberta) 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. 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 will require participating countries, upon ratification, to reduce their
emissions of carbon dioxide and other greenhouse gases.Canada ratified the Kyoto Protocol in late 2002.  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 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.  40 
   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;  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.  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 under
various circumstances, including if the other party to Enerplus hedge does not
perform its obligations under the hedge agreement.  41 
   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 distributable 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 Notes 3(b) and 8(b) to
the Funds audited consolidated financial statements for the year ended
December 31, 2003.  42 
   If Enerplus is unable to acquire additional
reserves, the value of the Trust Units and the Funds distributions to
unitholders may 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.  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.  Enerplus also distributes 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.  Acquisitions are subject to exploitation and
development risks which may affect the value of the Trust Units and
distributions to unitholders.  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.  Exploitation and development risks are mitigated by using highly
skilled staff, focusing exploitation efforts in areas in which Enerplus has
existing knowledge and expertise or access to such expertise, using up-to-date
technology to enhance methods and controlling costs to maximize returns.  Advanced oil and natural gas related
technologies such as three dimensional seismography, reservoir simulation
studies and horizontal drilling are also used by Enerplus to improve its
ability to find, develop and produce oil and natural gas.  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,  43 
   assumptions and prices prove to be inaccurate,
Enerplus actual reserves could vary materially from its reserve estimates.  In determining the purchase price of
acquisitions, Enerplus relies on estimates of reserves that may prove to be
inaccurate.  The price that Enerplus is willing to pay for reserve
acquisitions is based largely on its estimates of the reserves to be
acquired.  Actual reserves could vary
materially from these estimates. Consequently, the reserves that Enerplus
acquires may be less than it expected, which could adversely impact its 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 and approaches 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.  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 reduces amounts available for distribution 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, exceeds certain borrowing
thresholds 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.  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
one year revolving basis.  If the
lenders do not extend the facility at the end of the annual revolving period,
the loan will convert to a two year term loan. 
If this occurs, Enerplus may need to obtain alternate financing.  Any failure to obtain suitable replacement
financing may have a material adverse effect on Enerplus business, and
distributions to unitholders may be materially reduced.  44 
   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.  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.  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  45 
   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;  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.  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.  46 
   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 cost ceiling, ultimately
resulting in a charge against its earnings. 
Under United States generally accepted accounting principles (GAAP),
the cost ceiling is generally lower than under Canadian GAAP because the future
net cash flows used in the United States ceiling test are discounted to a
present value.  Accordingly, Enerplus
would have more risk of a ceiling test write-down in a declining price
environment if Enerplus reported under United States GAAP.  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 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 may affect the permitted amount of non-Canadian
resident ownership of the Trust Units and may result in increased withholding
tax on the Funds cash distributions paid to non-residents of Canada. See
General Development of Enerplus Resources Fund  Recent Developments 
Non-Resident Ownership, Mutual Fund Trust Status and Impact of 2004 Canadian
Federal Government Budget Proposals. In particular, the proposed transition
period within which Enerplus may be required to take certain steps to ensure
that it not be maintained primarily for the benefit of non-residents of
Canada (as defined in the Tax Act), currently proposed to end on January 1,
2007, may be shortened or eliminated.  Whether or not the transition period is shortened or
eliminated, Enerplus may not be able to take steps necessary to ensure that the
Fund not be maintained primarily for the benefits of non-residents within the
prescribed transition period, if any, and to ensure that the Fund maintains its
mutual fund trust status (as further discussed below). Even if the Fund is
successful in taking such measures, there can be no assurance that such
measures will be completed in a manner that is not detrimental to unitholders,
including both non-resident unitholders and the unitholders as a whole.
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.  47 
   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  Recent Developments  Non-Resident Ownership, Mutual Fund
Trust Status and Impact of 2004 Canadian Federal Government Budget
Proposals.  Should the status of the
Fund as a mutual fund trust be lost or successfully challenged by a relevant
tax authority, certain adverse consequences may arise for the Fund and its
unitholders. Some of the significant consequences of losing mutual fund trust
status are as follows:  The
Fund would be taxed on certain types of income distributed to unitholders,
including income generated by the royalties held by the Fund. Payment of this
tax may have adverse consequences for some unitholders, particularly
unitholders that are not residents of Canada and residents of Canada that are
otherwise exempt from Canadian income tax.  The
Fund would cease to be eligible for the capital gains refund mechanism
available under Canadian tax laws if it ceased to be a mutual fund trust.  Trust
Units held by unitholders that are not residents of Canada would become taxable
Canadian property.  These non-resident
holders would be subject to Canadian income tax on any gains realized on a
disposition of Trust Units held by them.  Trust
Units would not constitute qualified investments for registered retirement
savings plans (RRSPs), registered retirement income funds (RRIFs),
registered education savings plans (RESPs) or deferred profit sharing plans
(DPSPs).  If, at the end of any month,
one of these exempt plans holds Trust Units that are not qualified investments,
the plan must pay a tax equal to 1% of the fair market value of the Trust Units
at the time the Trust Units were acquired by the exempt plan.  An RRSP or RRIF holding non-qualified Trust
Units would be subject to taxation on income attributable to the Trust
Units.  If an RESP holds non-qualified
Trust Units, it may have its registration revoked by the Canada Customs and
Revenue Agency.  The
Fund would no longer be exempt from the application of the alternative minimum
tax provisions of the Tax Act.  In addition, Enerplus may take certain measures in the
future to the extent it believes necessary to ensure that the Fund maintains
its status as a mutual fund trust. 
These measures could be adverse to certain holders of Trust Units,
particularly non-residents of Canada (as defined in the Tax Act).  See Description of the Trust Units and the
Trust Indenture   Non-Resident
Ownership Provisions.  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 Enerplus.  The
Trust Units represent an equal fractional beneficial interest in the Fund and,
as such, 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.  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.  48 
   Changes in market-based factors may adversely
affect the trading price of the Trust Units.  The market price of the Trust Units is primarily a
function of anticipated distributions to unitholders and the value of the
properties owned by Enerplus.  The
market price of the Trust Units is therefore sensitive to a variety of market
based factors including, but not limited to, interest rates and the
comparability of the Funds Trust Units to other yield-oriented
securities.  Any changes in these
market-based factors may adversely affect the trading price of the Trust Units.  The limited liability of the Funds unitholders
is uncertain.  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. 
Although it is intended that every written contract or commitment of the
Fund will contain an express disavowal of liability of the unitholders and a
limitation of liability to Fund property, such protective provisions may not
operate to 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 would limit trust unitholder liability has been proposed or
discussed in certain jurisdictions of Canada but such legislation has not yet
been passed and there is no assurance that such legislation will be passed in
any jurisdiction or be enacted in a manner that will eliminate all risk of
unitholder liability.  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.  49 
   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 and 2003.  If the Fund were classified as a passive
foreign investment company, United States unitholders (other than most tax-exempt
investors) would be subject to adverse tax rules.  Under these adverse tax rules, United States unitholders
generally would be required to allocate any gain or any excess distributions,
which include any annual distributions other than in the first year the
unitholder held Trust Units, that is greater than 125% of the average annual
distributions received by that unitholder in the three preceding taxable years
or, if shorter, that unitholders holding period for Trust Units.  The amount allocated to the current taxable
year and any year prior to the first year in which Enerplus was a passive
foreign investment company would be taxed as ordinary income in the current
year.  The amount allocated to each of
the other taxable years would be subject to tax at the highest rate of tax in
effect for the applicable class of taxpayer for that year, and an interest
charge for the deemed deferral benefit would be imposed with respect to the
resulting tax attributable to each of the other taxable years.  Holders will not be able to make a
qualified electing fund election or, with respect to the Funds operating
subsidiaries that were considered to be passive foreign investment companies, a
mark-to-market election to protect themselves from these potential adverse
consequences if Enerplus were ultimately determined to be a passive foreign
investment company.  United States
unitholders are strongly urged to consult their own tax advisors regarding the
United States federal income tax consequences of Enerplus possible
classification as a passive foreign investment company and the consequences of
such classification.  United States and other non-resident unitholders
may be subject to additional taxation.  The Canadian Tax Act and the tax treaties between
Canada and other countries may impose additional withholding or other taxes on
the cash distributions or other property paid by the Fund to unitholders who
are not residents of Canada, and these taxes may change from time to time. In
particular, a proposal contained in the Canadian federal governments 2004 budget
would result in a 15% withholding tax being applied to return of capital
portion of distributions made to non-resident unitholders after 2004. See
Recent Developments  Non-Resident Ownership, Mutual Fund Trust Status and
Impact of 2004 Canadian Federal Government Budget Proposals.  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.  50 
   SELECTED CONSOLIDATED
FINANCIAL INFORMATION  The following table sets forth selected consolidated financial
information of Enerplus for the past three years.  Year Ended December 31,2003
  
  2002
  
  2001(in $ thousands, except per Trust Unit amounts)Gross oil and gas sales
  
  $
  935,819
  
  $
  630,167
  
  $
  589,312Net income
  
  249,600
  
  115,876
  
  180,269Per Trust Unit  Basic
  
  2.90
  
  1.61
  
  3.28Per Trust Unit  Diluted
  
  2.89
  
  1.61
  
  3.28Cash available for distribution
  
  379,055
  
  246,787
  
  316,454Per Trust Unit
  
  4.32
  
  3.32
  
  5.67Capital expenditures (net)
  
  145,151
  
  203,639
  
  152,216Total assets
  
  2,615,612
  
  2,471,631
  
  2,284,253Long term debt
  
  338,117
  
  361,729
  
  412,589  The above financial data has been taken from the
audited consolidated financial statements of the Fund for the years ended
December 31, 2003, 2002 and 2001.  The
audited consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles.  See Note 1 to the Funds audited annual consolidated financial
statements for the year ended December 31, 2003 for a description of the
significant accounting policies of the Fund.  Cash
Distributions to Unitholders  Reference is made to the information under the heading
Distributions to Unitholders in this Annual Information Form.  MANAGEMENTS DISCUSSION AND ANALYSIS  Managements discussion and analysis of financial
results for the year ended December 31, 2003, as contained on pages 54 to 76 of
the Funds Annual Report for the year ended December 31, 2003, is incorporated
by reference in this Annual Information Form.  51 
   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 2003.  Month
  
  High
  
  Low
  
  Close
  
  VolumeJanuary
  
  $
  29.00
  
  $
  27.66
  
  $
  28.77
  
  2,989,801February
  
  29.12
  
  26.15
  
  28.62
  
  2,579,126March
  
  29.12
  
  25.82
  
  28.15
  
  3,629,745April
  
  28.75
  
  27.07
  
  28.68
  
  3,001,059May
  
  32.98
  
  28.47
  
  32.85
  
  5,389,507June
  
  34.10
  
  27.25
  
  31.28
  
  6,654,795July
  
  34.09
  
  31.00
  
  34.09
  
  6,464,418August
  
  36.70
  
  33.70
  
  36.48
  
  3,967,781September
  
  37.10
  
  30.75
  
  35.25
  
  4,209,308October
  
  37.09
  
  35.12
  
  35.82
  
  3,352,752November
  
  37.10
  
  35.62
  
  36.15
  
  3,941,580December
  
  40.72
  
  36.15
  
  39.35
  
  5,620,527  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, principal occupation for the
past five years, year of appointment as a director of EnerMark and the number
of Trust Units beneficially owned, directly or indirectly, or over which
control or direction is exercised for each director of EnerMark are set forth
below:  Name and Residence
  
  Director
  Since
  
  Principal
  Occupation for Past Five Years(9)André Bineau (2)(3)Montréal, Québec,
  Canada
  
  February 1996
  
  Vice President of
  Association de bienfaisance et de retraite des policiers et policières de la
  Ville de Montréal (a municipal pension plan).Derek J.M. Fortune (3)(4)(6)
  Ottawa, Ontario,
  Canada
  
  June 2001
  
  Chairman of DF Consulting and Financial Services
  Inc. (a private consulting firm) since 2003. Prior thereto,
  Secretary/Manager, City of Ottawa Superannuation Fund (a municipal pension
  plan).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)(7)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)(6)
  Rosemere, Québec, Canada
  
  June 2001
  
  Corporate director.  52 
   Name and Residence
  
  Director
  Since
  
  Principal
  Occupation for Past Five Years(9)Eric P. Tremblay (9)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, André Bineauand
Harry B. Wheeler. Mr. Bineauis not standing for re-election as a
director of EnerMark at the 2004 annual general meeting and the resulting
vacancy on this committee will be filled by the directors following that
meeting. (3)The Corporate
Governance, Nominating and Environment, Health & Safety Committee is
comprised of Robert L. Zorich as Chairman, Derek J.M. Fortune and André Bineau.
Mr. Bineauis not standing for re-election as a director of EnerMark at the
2004 annual general meeting and the resulting vacancy on this committee will be
filled by the directors following that meeting. (4)The Compensation and
Human Resources Committee is comprised of Douglas R. Martin as interim
Chairman, Robert Normand and Derek J. M. Fortune. (5)The Reserves Committee
is comprised of Harry B. Wheeler and Donald T. West. (6)Prior to the merger of
Enerplus and EnerMark Income Fund on June 21, 2001, each of Derek J.M. Fortune
and Robert Normand was a director of Enerplus Resources Corporation (ERC),
the entity responsible for governance of Enerplus prior to the merger.  Mr. Fortune was a director of ERC since June
1992 and Mr. Normand was a director of ERC since March 1998. (7)From 1991 to 2000, Mr. Martin was director of
Coho Energy, Inc. (Coho), an oil and natural gas corporation that was listed
on the TSE and NASDAQ.  In 1999, Coho
filed for protection under United States federal bankruptcy law, from which it
was released in April, 2000.  The
directors of Coho were not held responsible for any actions.  Mr. Martin resigned as a director of Coho in
April of 2000. (8)In late 1997, Mr. Zorich
was appointed to the board of directors of Benz Energy Inc. (Benz), a
Vancouver Stock Exchange (now TSX Venture Exchange) listed company at the time,
as a representative of Mr. Zorichs employer, EnCap Investments L.L.C., 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 predecessor,
Enerplus Energy Services Ltd. (EES)), 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 or EES, but for simplicity, Enerplus has been utilized throughout the
above table.  Officers of
EnerMark  The name, municipality of residence, position held,
principal occupation for the past five years, year of appointment as an officer
of EnerMark and the number of Trust Units beneficially owned, directly or
indirectly, or over which control or direction is exercised 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.  53 
   Name and Residence
  
  Office
  
  Principal Occupation for Past Five Years(1)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.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.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.Ian C. Dundas
  Calgary, Alberta, Canada
  
  Vice President and Director,
  Business Development
  
  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. 
  Prior thereto, Director of Enron Canada Corp. merchant banking group
  since 1996.Wayne T. Foch
  Calgary, Alberta, Canada
  
  Vice President, Finance
  
  Vice President, Finance of
  Enerplus since February 2001.  Prior
  thereto, Treasurer of EMR Resource Management Ltd. (the management company of
  EnerMark Income Fund) since April 1996.David A. McCoy Calgary,
  Alberta, Canada
  
  General Counsel &
  Corporate Secretary
  
  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.  54 
   Name and Residence
  
  Office
  
  Principal Occupation for Past Five Years(1)Wayne G. Ford
  Calgary, Alberta, Canada
  
  Controller, Operations
  
  Controller 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.  Prior thereto, Client Service
  Manager with Applied Terravision Systems Inc. (a software company) since
  October 1996.Rodney D. Gray
  Calgary, Alberta, Canada
  
  Controller, Finance
  
  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.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 predecessor,
Enerplus Energy Services Ltd. (EES)), 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 or EES, 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 April 16, 2004, the directors and officers named
above beneficially own, directly or indirectly, an aggregate of 371,350 Trust
Units, representing approximately 0.4% of the outstanding Trust Units.  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.  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,
2001 or in any proposed transaction that would materially affect Enerplus.  MATERIAL CONTRACTS  The only material contract to which the Fund is a party,
other than contracts entered into in the normal course of business, is the
Trust Indenture, which is described under Information Respecting Enerplus
Resources Fund - Description of the Trust Units and the Trust Indenture.  A copy of the Trust Indenture was publicly
filed on January 5, 2004 and is available on the Funds SEDAR profile at
www.sedar.com.  55 
   INTERESTS OF EXPERTS  Sproule Associates Limited prepared the Sproule Report
in respect of the Funds oil and natural gas properties, a summary of which is
contained in this Annual Information Form. 
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 at such time.  As of March 5, 2004, the date of Deloitte & Touche LLPs auditors
report on the Funds consolidated financial statements as at and for the year
ended December 31, 2003, the partners of Deloitte & Touche LLP, as a group,
did not beneficially own, directly or indirectly, any 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
March 17, 2004 for its 2004 annual general meeting of Unitholders.  Furthermore, additional financial
information relating to the Fund is provided in the Funds audited consolidated
financial statements and managements discussion and analysis for the period
ended December 31, 2003.  56 
   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 January 1, 2004. The
reserves data consist of the following:  (a)(i)proved
and proved plus probable oil and gas reserves estimated as at January 1, 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 January 1, 2004 using constant prices and
costs; and  (ii)the
related estimated future net revenue.  Although our report is
effective January 1, 2004, we confirm that the information contained in our
report would be identical if it were presented December 31, 2003, the fiscal
year-end of the Fund.  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 January 1, 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.:  Independent
  Qualified
  Reserves Evaluator
  or Auditor
  
  Description
  and
  Preparation Date of
  Evaluation
  Report
  
  Location of
  Reserves
  (Country or
  Foreign
  Geographic
  Area)New
  Present Value of future Net Revenue
  (10% discount rate)Audited
  
  Evaluated
  
  Reviewed
  
  Total(in $
  thousands)Sproule Associates
  Limited
  
  Effective
  January 1, 2004 prepared November 2003 to March 2004
  
  Canada
  
  $
  Nil
  
  $
  1,929,723
  
  $
  312,654
  
  $
  2,242,377  A-1 
   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.  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, Canada
  Hans J. Firla, P. Eng.April 16, 2004
  Project Manager & AssociateMichael W. MaughanMichael W. Maughan, C.P.G., P. Geol.Manager, Geoscience & AssociateHari M. KapilHari M. Kapil, P. Eng.Senior Vice-President, Engineering  A-2 
   APPENDIX
B  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, 2003
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, 2003 using constant prices
and costs; and  (ii)the
related estimated future net revenue.  An independent qualified reserves evaluator has
evaluated and reviewed the Funds reserves data. The report of the independent
qualified reserves evaluator is presented as Appendix A 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 evaluator;  (b)met
with the independent qualified reserves evaluator to determine whether any
restrictions affected the ability of the independent qualified reserves
evaluator to report without reservation; and  (c)reviewed
the reserves data with management and the independent qualified reserves
evaluator.  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 report of the independent qualified reserves evaluator on the
reserves data; and  (c)the
content and filing of this report.  B-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Robert J. WatersRobert J. WatersSenior Vice President andChief Financial OfficerHarry B. WheelerHarry B. WheelerDirectorDonald T. WestDonald T. WestDirectorApril 22, 2004  
   Enerplus Resources Fund The Dome Tower Suite 3000, 333 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 2Z1 Telephone:(403) 298-2200 Fax:(403) 298-2211  www.enerplus.com