Exhibit 1      RENEWAL ANNUAL INFORMATION
FORM   For the year ended December
31, 2002   May 16, 2003  
    TABLE OF
CONTENTS  GLOSSARY OF TERMSABBREVIATIONSCONVERSIONPRESENTATION OF ENERPLUS FINANCIAL,
  OPERATIONAL AND RESERVES INFORMATIONFORWARD-LOOKING
  STATEMENTSNOTES TO READERSTRUCTURE OF ENERPLUS
  RESOURCES FUNDGENERAL DEVELOPMENT OF ENERPLUS
  RESOURCES FUNDOPERATIONAL INFORMATIONDescription of
  Principal PropertiesSummary of Production
  LocationsDrilling Activities and
  ResultsReserves
  ReconciliationHistorical
  Production RevenuesQuarterly
  Production HistoryQuarterly
  Netback HistoryQuarterly
  Capital ExpendituresExploration
  and DevelopmentMarketing
  ArrangementsImpact
  of Environmental Protection RequirementsOIL AND NATURAL GAS
  RESERVESINFORMATION
  RESPECTING ENERPLUS RESOURCES FUNDOperations
  of EnerplusDescription
  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 INFORMATIONMANAGEMENTS
  DISCUSSION AND ANALYSISMARKET FOR SECURITIESDIRECTORS AND OFFICERSADDITIONAL INFORMATION  i  
    GLOSSARY OF TERMS  Unless the context otherwise requires, in this Renewal Annual
Information Form, the following terms and abbreviations have the meanings set
forth below.  EGEM means Enerplus Global Energy Management
Company, an indirect wholly owned subsidiary of the Fund and, prior to its
acquisition by Enerplus, the former manager of Enerplus pursuant to the
Management Agreement;  EnerMark means EnerMark Inc., a corporation amalgamated
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;  ERC means Enerplus Resources Corporation, a
corporation amalgamated under the Business Corporations Act (Alberta) and a
wholly owned subsidiary of EnerMark;  Established Reservesmeans Proven Reserves plus 50% of
Probable Reserves, before the deduction of royalties and based on escalated
price and cost assumptions, unless otherwise indicated;  Fund means Enerplus Resources Fund;  Governance Agreement means the governance agreement
dated June 21, 2001 among the Fund, EnerMark, ERC, the Trustee and EGEM, as may
be amended, restated or supplemented from time to time;  Internalization Transaction means the acquisition by the Fund,
through a wholly owned subsidiary, of all of the outstanding shares of EGEM on
April 23, 2003, as more fully described under the heading General Development
of Enerplus Resources Fund - Recent Developments Since Fiscal Year-End -
Management Internalization Transaction in this Renewal Annual Information
Form;  Management Agreement means the Amended and Restated
Management, Advisory and Administrative Agreement dated June 21, 2001, as
amended December 31, 2001, made among the Fund, EnerMark, ERC, the Trustee and
EGEM, as may be amended, supplemented or restated from time to time, and in
respect of which EGEM has assigned its interest to EnerMark effective April 23,
2003;  Merger means the merger of Enerplus Resources Fund
and EnerMark Income Fund effective June 21, 2001, pursuant to which such
entities continued as Enerplus Resources Fund;  Proven
Reserves and Probable Reserves have the meanings given
to those terms in the notes under Oil and Gas Reserves;  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 February
10, 2003 and effective January 1, 2003, utilizing commodity price forecasts of
Sproule dated January 1, 2003;  Tax
Actmeans the Income Tax Act (Canada);  Trust Indenture means the Amended and Restated Trust Indenture
dated June 21, 2001 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.  ii 
   ABBREVIATIONS  Oil and Natural Gas Liquids
  
  Natural GasBbls - barrels
  
  Bcf - billion cubic feetBbls/d - barrels per day
  
  Mcf - thousand cubic feetMbbls - thousand barrels
  
  Mcf/d - thousand cubic feet per dayMMbbls - million barrels
  
  MMcf - million cubic feetNGLs - natural gas liquids
  
  MMcf/d - million cubic feet per dayMMBTU - million British Thermal Units
  Other  ARTCmeans Alberta Royalty Tax Credit.  BOEmeans barrel of oil equivalent,
using the conversion factor of 6 Mcf of natural gas being equivalent to one
barrel of oil.  The conversion factor
used to convert natural gas to oil equivalent is not necessarily based upon either
energy or price equivalents at the relevant time.  BOE/dmeans BOE per day.  MBOEmeans thousand barrels of oil
equivalent.  WTIWest Texas Intermediate at Cushing,
Oklahoma, the benchmark crude oil for pricing purposes.  CONVERSION  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
  
  0.405hectares
  
  acres
  
  2.471GJ
  
  MMBTU
  
  0.950  iii 
   PRESENTATIONOF ENERPLUS FINANCIAL, OPERATIONAL AND RESERVES
INFORMATION  The
financial information included and incorporated by reference in this Renewal
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 10 to the Funds
audited consolidated financial statements for the year ended December 31, 2002.  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 (described by Enerplus as Proven Reserves)
but also probable reserves (see the definition of Probable Reserves), 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 Proven Reserves.  Because
Enerplus has prepared this Renewal Annual Information Form in accordance with
Canadian disclosure requirements, Enerplus has disclosed reserves designated as
Probable Reserves and Established 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 escalated 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.  In this
Renewal Annual Information Form, all estimates of oil and natural gas reserves
and production are on a gross basis before deduction of royalties, unless
otherwise indicated.  Enerplus actual
oil and gas reserves and production will be greater than or less than the
estimates provided herein.  Enerplus has adopted the standard of 6 Mcf:1 BOE when converting
natural gas to BOE.  In this Renewal Annual Information Form, unless otherwise indicated,
all dollar amounts are in Canadian dollars and all references to $
are to Canadian dollars.  FORWARD-LOOKING STATEMENTS  This Renewal 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  iv 
   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 Renewal 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 Renewal 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.  NOTES
TO READER  Merger of Enerplus Resources Fund and EnerMark Income
Fund  On June 21, 2001, Enerplus
Resources Fund and EnerMark Income Fund merged and continued as Enerplus
Resources Fund. The nature of the business combination was such that, as the
former unitholders of EnerMark Income Fund held approximately 69% of the
outstanding Trust Units of the combined Enerplus Resources Fund at the date of
the Merger, the Merger has been accounted for using the reverse take-over form
of the purchase method of accounting for business combinations.  Accordingly, unless otherwise noted, all historical
financial and operational information for the 2001 fiscal year contained in
this Renewal Annual Information Form, including 2001 information contained in
the managements discussion and analysis of financial condition and results of
operations incorporated by reference in this Renewal Annual Information Form,
is that of EnerMark Income Fund up to June 21, 2001 and that of the merged Fund
thereafter.  Where applicable,
historical per Trust Unit information has been restated to reflect the exchange
ratio of 0.173 of an Enerplus Trust Unit for each trust unit of EnerMark Income
Fund effective under the Merger.  Management Internalization Transaction  On April 23, 2003, the Fund,
through a wholly owned subsidiary, acquired all of the outstanding shares of
EGEM pursuant to the Internalization Transaction.  The result of this transaction was to effectively eliminate the
payment of external management and administration fees by Enerplus to EGEM
under the Management Agreement. 
Although the Management Agreement still exists, EGEM has assigned and
transferred its rights under the Management Agreement to EnerMark and as a
result, no external management or administration fees are paid by Enerplus and
all executives and employees who provide services to Enerplus are now employed
by wholly owned subsidiaries of the Fund. 
As a result, this Renewal Annual Information Form does not contain a
detailed description of the Management Agreement or the external management
services that, prior to April 23, 2003, were provided to Enerplus by EGEM.  v 
   ENERPLUS RESOURCES FUND  Renewal Annual Information
Form For the year ended December
31, 2002  STRUCTURE OF ENERPLUS RESOURCES FUND  Enerplus Resources Fund  Enerplus Resources Fund is an energy investment trust created under the
laws of the Province of Alberta in 1986 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 and ERC), an unsecured note issued by EnerMark to the
Fund and 95% and 99% royalties on the crude oil and natural gas property interests
of EnerMark and ERC, 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 undeveloped lands. 
Development efforts are concentrated on optimizing production from existing
and new crude oil and natural gas reserves.  EnerMark Inc. and Enerplus Resources Corporation  Each of EnerMark and ERC are corporations organized under the Business
Corporations Act (Alberta). 
All of the issued and outstanding shares of EnerMark are owned by the
Fund, and all of the issued and outstanding shares of ERC are owned by
EnerMark.The board of directors of
EnerMark is the entity responsible for the governance of Enerplus.  All of the employees responsible for the
operations of Enerplus are employed by subsidiaries of the Fund.  EnerMark and ERC, 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 and ERC
to the Fund and from the Fund to its unitholders are set forth below:     2 
   GENERAL DEVELOPMENTOF 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
issued an aggregate of 8,911,667 Trust Units to former unitholders of Westrock
I and Westrock II in connection with the merger.  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.  Strategic Affiliation with El Paso
Corporation  On August 3, 2000, Enerplus announced that it had formed a strategic
affiliation with El Paso Corporation (El Paso) of Houston, Texas through the
acquisition, by an indirect wholly owned subsidiary of El Paso, of 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 pursuant
to the Internalization Transaction, which resulted in the termination of this
affiliation.  See Recent Developments
Since Fiscal Year-End - Management Internalization Transaction.  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 completed the
Merger pursuant to which each trust unit of EnerMark Income Fund (an EIF
Unit) was exchanged for 0.173 of a Trust Unit of Enerplus. A total of
43,525,961 Trust Units of the Fund (as well as 2,507,330 warrants to acquire
Trust Units) were issued to former securityholders of EnerMark Income Fund
pursuant to the Merger.  Enerplus and EnerMark 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  3 
   and Western Star Exploration Ltd., Pursuit Resources Corp., EBOC Energy
Ltd. and Cabre Exploration Ltd., in addition to an 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.  The Celsius properties were primarily located in Alberta and
northeastern British Columbia.  Many of
the Celsius properties were located in areas in which Enerplus was active prior
to the acquisition, including the Verger, Countess, Pine Creek and Deep Basin
areas.  The gross average daily
production from the Celsius properties for September 2002 was approximately
5,750 BOE/d consisting of 22,476 Mcf/d of natural gas, 1,724 Bbls/d of crude
oil and 280 Bbls/d of NGLs.  Enerplus
estimates that the Celsius properties contained approximately 18 MMBoe of
Established Reserves as of July 31, 2002. 
Included in the acquisition were approximately 103,000 net acres of
undeveloped land.  Cross-Border
Equity Offering  On November 29, 2002 (and an over-allotment option completed on
December 6, 2002), Enerplus completed a cross-border offering of 7,959,300
Trust Units at a price of $26.00 per Trust Unit for proceeds of approximately
$193.7 million, net of issuance costs. 
The net proceeds of the offering were used to repay bank indebtedness of
Enerplus which was incurred in connection with the Celsius acquisition and to
fund Enerplus ongoing acquisition and development activities, including the
subsequent acquisition of PCC described below. 
See Recent Developments Since Fiscal Year-End.  Recent Developments
Since Fiscal Year-End  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.  Enerplus estimates that, as of October 1,
2002 (the economic effective date for the transaction) and after giving effect
to the NPI, the PCC properties contained 17.2 MMBOE of Established Reserves and
produced approximately 4,380 BOE/d, consisting of 19.4 MMcf/day of natural gas
and 1,140 Bbls/day of crude oil and NGLs. 
The production from the PCC properties is weighted approximately 74%
natural gas and 26% crude oil and NGLs. 
The PCC properties are located primarily in Alberta, with 85% of the
value of the assets located within Enerplus strategic areas of operation, and
are concentrated in the significant central Alberta natural gas producing areas
of Hanlan, Basing, Shaw, Pine Creek, Kaybob South and Minehead.  Also included in the acquisition was
approximately 22,850 net acres of undeveloped land plus seismic data.  The oil and natural gas reserves of PCC 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 PCC properties has been included in Enerplus
results since March 5, 2003 but is not included in the information contained in
this Renewal Annual Information Form as the transaction was completed in 2003.  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 for cash consideration of $48.9 million, plus
adjustments for the working capital of EGEM. 
Prior to the acquisition, EGEM received management fees for Enerplus for  4 
   providing administrative and management services to the Fund and its
operating subsidiaries pursuant to the Management Agreement.  As part of this Internalization 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 the Internalization
Transaction, EGEM assigned and transferred all of its rights and obligations
under the Management Agreement to EnerMark.  Property Disposition Program  Enerplus routinely evaluates its property portfolio and disposes of
properties that are viewed as non-core holdings.  Enerplus has undertaken a process to sell several non-core
properties that range from southeastern Saskatchewan to northwestern British
Columbia.  Enerplus estimates that the
properties being considered for sale will produce approximately 4,315 BOE/d in
2003, comprised of approximately 3,108 Bbls/d of crude oil and NGLs and 7.2
MMcf/d of natural gas.  Enerplus has
established price retention thresholds on all properties and all sales will be
contingent upon exceeding those minimum thresholds.  5 
   OPERATIONAL INFORMATION  As stated in the Notes to Reader, all historical operational
information for the 2001 fiscal year contained in this Renewal Annual
Information Form is based on the historical operational results of EnerMark
Income Fund.  The production and
operational information relating to the pre-Merger Enerplus Resources Fund has
only been included since June 21, 2001, the effective date of the Merger.  The historical operational information for
the 2002 fiscal year, as well as the reserve information as of both January 1,
2002 and January 1, 2003, is information of the merged Fund.  Description
of Principal Properties  All of Enerplus oil and natural gas property interests are located in
western Canada in the provinces of Alberta, British Columbia and Saskatchewan
(with a minimal landholding interest in the province of Manitoba). All of
Enerplus major properties have related field production facilities and
infrastructure to accommodate Enerplus 
production. Enerplus does not own or operate any transportation
pipelines. Production volumes for the year ended December 31, 2002 from
Enerplus properties consisted of approximately 44% crude oil and NGLs and 56%
natural gas on a BOE basis.  This is
comprised of average daily production 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,
compared to 20,592 Bbls/d of crude oil, 3,978 Bbls/d of NGLs and 176.7 MMcf/d
of natural gas for a total of 54,015 BOE/d during 2001.  For the last six months of 2001, following
the Merger, Enerplus property interests yielded average production of 22,765
Bbls/d of crude oil, 4,415 Bbls/d of NGLs and 202.1 MMcf/d of natural gas, for
a total of 60,871 BOE/d.  As at January
1, 2003 the oil and natural gas property interests held by Enerplus were
estimated to contain Established Reserves of 141.3 MMbbls of crude oil and NGLs
and 1,141 Bcf of natural gas for a total of 330.4 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 65% of 2002 average daily production, and a joint venture
business unit which accounted for approximately 35% of 2002 daily production.
This restructuring will enable 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 center with a complement of engineers,
geologists, operations personnel, and landmen supported by an efficient
corporate structure.  Skill sets within
each business unit are tailored to compliment the unique demands and
opportunities within each area.  The following paragraphs discuss each of the Enerplus business units
and their principal producing properties including, where applicable, the
additional properties or working interests acquired through acquisitions during
2002. All production information represents Enerplus net working interest in
these properties before deduction of royalty interests owned by others. All
references to reserve volumes are based upon the estimated volumes contained
within the Sproule Report applicable to Enerplus gross working interest
reserves, before deduction of any royalties.  Joint Venture Business
Unit  The Joint Venture Business Unit accounts for approximately one third 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
sophisticated projects than Enerplus might pursue on its own.  Production for the year ended December 31, 2002 in this business unit
averaged 5,492 Bbls/d of crude oil, 2,331 Bbls/d of NGLs and 85.5 MMcf/d of
natural gas for a total of 22,068 BOE/d. As at January 1, 2003, the Joint
Venture Business Units property interests contained 106,546 MBOE of
Established Reserves consisting of 33,094 Mbbls of crude oil and NGLs and 440.7
Bcf of natural gas.  6 
   The key properties within this business unit include the sweet, liquids
rich natural gas plays in Deep Basin 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 Progress Halfway Gas Unit and Hayter operated by Anadarko
Canada Corporation; and interests in the Mount Benjamin property operated by
Petro-Canada. The Mount Benjamin property is a foothills deep natural gas
property where, during 2002, three wells were drilled, completed and tied-in
late in the year. 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 common.  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, if successful, 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).  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% interest in a sweetening and absorption facility at Minnehik Buck Lake; a 2%
interest in the Ram River sweetening & refrigeration facility; and an 11%
interest in an emulsion treating and water disposal facility at Hayter.  Enerplus expects 2003 capital expenditures for this partner-operated
business unit to remain consistent with 2002 or to increase, with approximately
75% of Enerplus joint venture capital budget focused on natural gas-weighted
projects and 25% on oil-weighted projects. 
Additionally, as a continuation of its strategic investments in the
Athabasca oil sands fairway, Enerplus will be funding the initial phases of the
Oil Sands Lease #24 steam assisted gravity drainage (SAGD) development
project and expects to spend up to $7.0 million on this project in 2003, with
initial production expected in 2004.  Southern Business Unit  The Southern Business Unit is Enerplus most active 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 2002. The Medicine Hat
Glauconitic C Pool, in which Enerplus acquired additional working interests
in 2002, is also in this business unit along with the Midale/Ratcliffe area,
which has significant crude oil production.  Production for the year ended December 31, 2002 in this business unit
averaged 3,236 Bbls/d of crude oil, 14 Bbls/d of NGLs and 56.3 MMcf/d of
natural gas for a total of 12,638 BOE/d. As at January 1, 2003, the Southern
Business Units property interests contained 99,809 MBOE of Established
Reserves consisting of 23,254 Mbbls of crude oil and NGLs and 459.3 Bcf of
natural gas.  The Southern Business Units key natural gas producing properties
include Hanna Garden Plains, Bantry, Verger, and Medicine Hat Sun Valley, all
of which have 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
2003, including higher density drilling within existing producing areas. The
Celsius acquisition, completed in late 2002, has added approximately 300
locations to the existing project inventory. Confirmation of the viability of
the increased density of well spacing will add further development
opportunities in the future. Enerplus also plans to continue crude oil
development of the Medicine Hat Glauconitic C Pool and pursue other
waterflood opportunities in the area.  7 
   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 for the year ended December 31, 2002 in this business unit
averaged 8,681 Bbls/d of crude oil, 202 Bbls/d of NGLs and 10.0 MMcf/d of
natural gas for a total of 10,558 BOE/d. As at January 1, 2003, the Eastern
Business Units property interests contained 51,618 MBOE of Established
Reserves consisting of 41,265 Mbbls of crude oil and NGLs and 62.1 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 Chauvin, David, Giltedge,
Joarcam, and Shorncliffe. 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 and added approximately 2.9 million
BOE of Established Reserves.  The key waterflood recovery projects in this business unit were
reviewed in 2002 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 2003 will build on Enerplus historical success and continue to focus on
improving and expanding its existing waterfloods to increase production and
recovery. Enerplus also intends to pursue new shallow natural gas from coal bed
methane potential in the area. 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 lies to the
west and southwest of the city of Edmonton, Alberta and provides a variety of
production predominantly weighted to light quality sweet oil and liquids rich
natural gas. Given the relatively higher operating costs in many fields in this
area, profitability is sensitive to commodity pricing and Enerplus focus is on
controlling operating costs in order to maximize the value of these assets.  Production for the year ended December 31, 2002 from this business unit
averaged 3,099 Bbls/d of crude oil, 1,367 Bbls/d of NGLs and 36.1 MMcf/d of
natural gas for a total of 10,485 BOE/d. As at January 1, 2003, the Central
Business Units property interests contained 52,730 MBOE of Established
Reserves consisting of 33,174 Mbbls of crude oil and NGLs and 117.3 Bcf of
natural gas.  The Central Business Units key producing property for 2002 is Pembina,
primarily an 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 Cherhill.  Development activity during 2002 was primarily targeted at maintaining
light oil production in the Pembina and Sylvan Lake areas and developing new
shallow natural gas production in Pembina, Bashaw and Sylvan Lake. Pembina is a
large, low decline Cardium zone oil field that has benefited from ongoing
development which has increased production by 27% within the past two
years.  An initiative to exploit the
shallow natural gas potential in  8 
   the Central Business Unit was commenced in the latter half of 2002. The
early results of this project have been encouraging, as natural gas production
has grown significantly, and have led to further development planned in 2003 to
assess the economic viability of the program.  The focus of Enerplus investment activity in 2003 will be to further
develop its shallow natural gas program, including the continued evaluation of
natural gas from coal bed methane potential. 
Enerplus also intends to continue the infill drilling and recompletion
initiatives to maintain its light 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 Bonanza, Pouce Coupe, and
Utikima.  Production for the year ended December 31, 2002 from this business unit
averaged 2,780 Bbls/d of crude oil, 496 Bbls/d of NGLs and 22.6 MMcf/d of
natural gas for a total of 7,035 BOE/d. As at January 1, 2003, the Northern
Business Units property interests contained 19,740 MBOE of Established
Reserves consisting of 9,539 Mbbls of crude oil and NGLs and 61.2 Bcf of
natural gas.  During 2002, development activities were primarily directed to
improving light oil production at Valhalla and optimizing natural gas
production at Progess, Bonanza, Komie and Valhalla through facility upgrades
and development drilling. Since 1996, and particularly in the last two years,
Enerplus has steadily increased Valhalla production through development
efforts. In 2002, two additional wells were drilled in the crude oil portion of
the Valhalla Halfway J pool to enhance oil recovery and optimize the production
from this pool.  Development activities for 2003 will target additional development at
Valhalla and Progress 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 in 2003 and
into the future. The divestment of non-core properties in the north central
Alberta area surrounding Slave Lake is being considered to further focus
operations in this business unit.  Summary
of Production Locations  During the year ended December 31, 2002, on a BOE basis, 89% of
Enerplus production was derived from Alberta, 8% from Saskatchewan and 3% 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, 2002:  Business Unit and Property
  
  Product
  
  LocationCrude Oil
  (Bbls/d)
  
  NGLs
  (Bbls/d)
  
  Natural
  Gas 
  (Mcf/d)
  
  Total
  (BOE/d)
  
  Alberta
  (BOE/d)
  
  Saskatchewan
  (BOE/d)
  
  B.C.
  (BOE/d)Joint
  Venture Business UnitMount Benjamin
  
  
  
  10
  
  11,063
  
  1,854
  
  1,854
  
  
  
  Elmworth
  
  
  
  360
  
  5,001
  
  1,194
  
  1,194
  
  
  
  Progress
  
  45
  
  73
  
  4,104
  
  802
  
  802
  
  
  
  South Wapiti
  
  
  
  168
  
  3,491
  
  750
  
  750
  
  
  
  Hayter
  
  679
  
  
  
  16
  
  682
  
  682
  
  
  
  Other
  
  4,768
  
  1,720
  
  61,795
  
  16,786
  
  14,044
  
  1,519
  
  1,223Total
  
  5,492
  
  2,331
  
  85,470
  
  22,068
  
  19,326
  
  1,519
  
  1,223  9 
   Product
  
  LocationBusiness Unit and Property
  
  Crude Oil
  (Bbls/d)
  
  NGLs
  (Bbls/d)
  
  Natural
  Gas 
  (Mcf/d)
  
  Total
  (BOE/d)
  
  Alberta
  (BOE/d)
  
  Saskatchewan
  (BOE/d)
  
  B.C.
  (BOE/d)Southern
  Business UnitBantry
  
  
  
  
  
  13,757
  
  2,293
  
  2,293
  
  
  
  Hanna Garden
  
  2
  
  
  
  12,616
  
  2,105
  
  2,105
  
  
  
  Medicine Hat
  
  1,226
  
  
  
  1,222
  
  1,430
  
  1,430
  
  
  
  Verger
  
  8
  
  
  
  7,609
  
  1,276
  
  1,276
  
  
  
  Medicine Hat Sun
  Valley
  
  
  
  
  
  7,318
  
  1,220
  
  1,220
  
  
  
  Other
  
  2,000
  
  14
  
  13,808
  
  4,314
  
  2,256
  
  2,058
  
  Total
  
  3,236
  
  14
  
  56,330
  
  12,638
  
  10,580
  
  2,058
  
  Eastern
  Business UnitJoarcam
  
  2,075
  
  160
  
  5,726
  
  3,189
  
  3,189
  
  
  
  Giltedge
  
  1,635
  
  
  
  386
  
  1,699
  
  1,699
  
  
  
  Gleneath
  
  1,004
  
  22
  
  407
  
  1,094
  
  
  
  1,094
  
  Auburndale
  
  582
  
  
  
  553
  
  674
  
  674
  
  
  
  Kessler
  
  571
  
  
  
  101
  
  588
  
  588
  
  
  
  Other
  
  2,814
  
  20
  
  2,876
  
  3,314
  
  2,833
  
  481
  
  Total
  
  8,681
  
  202
  
  10,049
  
  10,558
  
  8,983
  
  1,575
  
  Central
  Business UnitPembina
  
  2,151
  
  114
  
  1,450
  
  2,507
  
  2,507
  
  
  
  Ferrier
  
  6
  
  212
  
  4,358
  
  944
  
  944
  
  
  
  Sylvan Lake
  
  463
  
  111
  
  1,959
  
  901
  
  901
  
  
  
  Kaybob South
  
  
  
  227
  
  2,920
  
  714
  
  714
  
  
  
  Cherhill
  
  170
  
  1
  
  2,901
  
  655
  
  655
  
  
  
  Other
  
  309
  
  702
  
  22,525
  
  4,764
  
  4,764
  
  
  
  Total
  
  3,099
  
  1,367
  
  36,113
  
  10,485
  
  10,485
  
  
  
  Northern
  Business UnitValhalla
  
  372
  
  125
  
  8,755
  
  1,956
  
  1,956
  
  
  
  Progress
  
  705
  
  21
  
  2,318
  
  1,112
  
  1,112
  
  
  
  Bonanza
  
  
  
  12
  
  3,406
  
  580
  
  580
  
  
  
  Pouce Coupe
  
  279
  
  20
  
  555
  
  392
  
  392
  
  
  
  Utikima
  
  352
  
  1
  
  53
  
  362
  
  362
  
  
  
  Other
  
  1,072
  
  317
  
  7,468
  
  2,633
  
  2,132
  
  
  
  501Total
  
  2,780
  
  496
  
  22,555
  
  7,035
  
  6,534
  
  
  
  501TOTAL
  
  23,288
  
  4,410
  
  210,517
  
  62,784
  
  55,908
  
  5,152
  
  1,724  10 
   Drilling Activities and
Results  During 2002, Enerplus participated in the drilling of 421 gross wells
(299.5 net wells) with a 99% net well success rate.  The following table summarizes the number and type of wells that
Enerplus drilled or participated in the drilling of for the years ended
December 31, 2002 and 2001.  Enerplus
did not participate in drilling any exploratory wells in any such period.  Other than wells designated as Dry in the
table below, all wells described in the table are capable of production.  Year Ended December 31,2002
  
  2001(3)Development Wells
  
  Gross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)Oil
  
  78
  
  30.7
  
  104
  
  37.7Natural gas
  
  335
  
  264.6
  
  429
  
  279.4Dry
  
  8
  
  4.2
  
  13
  
  4.5Total working interest wells (3)
  
  421
  
  299.5
  
  546
  
  321.6
  
 Notes: (1)Gross means the number of wells in which Enerplus has an interest. (2)Net means the product of the total number of gross wells multiplied by
Enerplus percentage working interest in those wells. (3)In 2001, the pre-Merger Enerplus Resources Fund participated in the
drilling of 14.6 net oil wells and 13.4 net natural gas wells, for a total of
28.0 net working interest wells, which are not included in the above table.  Oil
and Natural Gas Wells and Undeveloped Landholdings  The following table summarizes, as at December 31, 2002, Enerplus
interests in producing and shut-in wells which may be capable of production,
along with Enerplus interests in undeveloped oil and natural gas leases and
rights.  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.  As of December 31, 2002, Enerplus had
assigned a value of $23.2 million to its undeveloped land holdings.  Producing Wells
  
  Shut-in Wells(1)
  
  LandholdingsOil
  
  Natural Gas
  
  Oil
  
  Natural Gas
  
  (thousands of acres)Area
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)Alberta
  
  2,720
  
  1,170
  
  4,460
  
  2,108
  
  556
  
  215
  
  206
  
  75
  
  907.5
  
  382.7British Columbia
  
  92
  
  26
  
  114
  
  27
  
  13
  
  3
  
  52
  
  16
  
  121.6
  
  56.1Saskatchewan
  
  2,344
  
  453
  
  330
  
  237
  
  244
  
  33
  
  7
  
  1
  
  34.1
  
  23.8Other
  
  
  
  
  
  20
  
  20
  
  
  
  
  
  
  
  
  
  0.6
  
  0.6Total
  
  5,156
  
  1,649
  
  4,924
  
  2,392
  
  813
  
  251
  
  265
  
  92
  
  1,063.8
  
  463.2  
 Notes: (1)Shut-in wells means wells which are not producing but which may be
capable of production. (2)Gross wells and acres are defined as the total number of wells and acres
in which Enerplus has an interest. (3)Net wells and acres are defined as the aggregate of the numbers
obtained by multiplying each gross well and acre by Enerplus percentage
working interest therein.  11 
   Reserves Reconciliation  The table below reconciles the oil and natural gas reserves of Enerplus
from January 1, 2002 to January 1, 2003.  Crude Oil
  
  Natural Gas
  
  NGLs
  
  Total
  
  Established Reserves(MBOE)(Mbbls)
  
  (MMcf)
  
  (Mbbls)
  
  (MBOE)Proven
  
  Probable(1)
  
  Proven
  
  Probable(1)
  
  Proven
  
  Probable(1)
  
  Proven
  
  Probable(1)Reserves as of January 1,
  2002
  
  94,847
  
  37,643
  
  951,133
  
  260,689
  
  16,114
  
  4,674
  
  269,482
  
  85,765
  
  312,365Production
  
  8,500
  
  
  
  76,839
  
  
  
  1,610
  
  
  
  22,917
  
  
  
  22,917Acquisitions
  
  7,787
  
  5,458
  
  79,333
  
  19,541
  
  1,096
  
  424
  
  22,105
  
  9,139
  
  26,675Divestments
  
  615
  
  
  
  183
  
  
  
  
  
  
  
  646
  
  
  
  646Drilling, Development and
  Revisions
  
  11,728
  
  (9,652
  )
  48,469
  
  (2,652
  )
  436
  
  (460
  )
  20,243
  
  (10,554
  )
  14,966Reserves as at January 1,
  2003
  
  105,247
  
  33,449
  
  1,001,913
  
  277,578
  
  16,036
  
  4,638
  
  288,269
  
  84,350
  
  330,444  
 Note: (1)No discount factor has
been applied to the Probable Reserves to account for the risk associated with
the probability of obtaining production from such reserves.  Historical Production Revenues  Gross production revenues (excluding hedging and before deduction of
royalties payable to others) for each of Enerplus products during the years
ended December 31, 2002 and 2001 are as follows:  2002
  
  2001$ Million
  
  % of Total Revenue
  
  $ Million
  
  % of Total RevenueCrude Oil
  
  $
  292.2
  
  46
  %
  $
  229.1
  
  39
  %NGLs
  
  41.3
  
  7
  %
  45.2
  
  8
  %Natural gas
  
  296.7
  
  47
  %
  315.0
  
  53
  %Total
  
  $
  630.2
  
  100
  %
  $
  589.3
  
  100
  %  Quarterly Production History  The following tables show Enerplus average working interest sales
volumes (before deduction of royalties payable to others) for each of the last
eight fiscal quarters and the years then ended.  Average Daily Production  Year Ended December 31, 2002First
  Quarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  YearCrude oilLight/medium (Bbls/d)
  
  17,077
  
  16,834
  
  16,876
  
  17,244
  
  17,008Heavy (Bbls/d)
  
  5,889
  
  5,986
  
  6,684
  
  6,551
  
  6,280Total crude oil (Bbls/d)
  
  22,966
  
  22,820
  
  23,560
  
  23,795
  
  23,288NGLs (Bbls/d)
  
  4,374
  
  4,431
  
  4,095
  
  4,740
  
  4,410Total liquids (Bbls/d)
  
  27,340
  
  27,251
  
  27,655
  
  28,535
  
  27,698Natural gas (Mcf/d)
  
  211,713
  
  203,370
  
  198,452
  
  228,480
  
  210,517Total (BOE/d)
  
  62,626
  
  61,146
  
  60,730
  
  66,615
  
  62,784  12 
   Year Ended December 31, 2001FirstQuarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  YearCrude oilLight/medium (Bbls/d)
  
  14,273
  
  13,425
  
  16,535
  
  17,468
  
  15,437Heavy (Bbls/d)
  
  4,513
  
  4,561
  
  5,933
  
  5,593
  
  5,155Total crude oil (Bbls/d)
  
  18,786
  
  17,986
  
  22,468
  
  23,061
  
  20,592NGLs (Bbls/d)
  
  3,127
  
  3,936
  
  4,559
  
  4,272
  
  3,978Total liquids (Bbls/d)
  
  21,913
  
  21,922
  
  27,027
  
  27,333
  
  24,570Natural gas (Mcf/d)
  
  152,367
  
  149,201
  
  199,823
  
  204,467
  
  176,671Total (BOE/d)
  
  47,308
  
  46,789
  
  60,331
  
  61,411
  
  54,015  Quarterly Netback History  The following tables show Enerplus average netbacks received for each
of the last eight fiscal quarters and the years then ended.  Crude oil and NGLs Netbacks ($ per Bbl)  Year Ended December 31, 2002FirstQuarter
  
  Second
  Quarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  YearSales price
  
  $
  26.66
  
  $
  33.57
  
  $
  35.69
  
  $
  35.76
  
  $
  32.99Hedging gains (costs)
  
  (0.09
  )
  (0.20
  )
  (0.68
  )
  (0.71
  )
  (0.42
  )Royalties
  
  (5.01
  )
  (6.33
  )
  (6.56
  )
  (7.96
  )
  (6.49
  )Operating costs(1)
  
  (7.02
  )
  (6.19
  )
  (8.17
  )
  (8.34
  )
  (7.45
  )Netback
  
  $
  14.54
  
  $
  20.85
  
  $
  20.28
  
  $
  18.75
  
  $
  18.63Average selling price Crude oilLight/medium
  
  $
  29.88
  
  $
  37.08
  
  $
  39.17
  
  $
  38.70
  
  $
  36.23Heavy
  
  $
  23.67
  
  $
  29.82
  
  $
  32.96
  
  $
  30.19
  
  $
  29.34Total crude oil
  
  $
  28.29
  
  $
  35.18
  
  $
  37.41
  
  $
  36.36
  
  $
  34.37NGLs
  
  $
  18.15
  
  $
  25.28
  
  $
  25.81
  
  $
  32.74
  
  $
  25.68  Year Ended December 31, 2001FirstQuarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  YearSales price
  
  $
  35.13
  
  $
  33.58
  
  $
  33.62
  
  $
  21.63
  
  $
  30.58Hedging gains (costs)
  
  
  
  (0.78
  )
  (0.63
  )
  3.41
  
  0.61Royalties
  
  (6.98
  )
  (6.70
  )
  (6.45
  )
  (3.89
  )
  (5.91
  )Operating costs(1)
  
  (5.90
  )
  (6.49
  )
  (7.89
  )
  (8.28
  )
  (7.25
  )Netback
  
  $
  22.25
  
  $
  19.61
  
  $
  18.65
  
  $
  12.87
  
  $
  18.03Average selling price Crude oilLight/medium
  
  $
  37.10
  
  $
  36.86
  
  $
  37.95
  
  $
  24.04
  
  $
  33.55Heavy
  
  $
  20.93
  
  $
  22.34
  
  $
  27.20
  
  $
  14.39
  
  $
  21.27Total crude oil
  
  $
  33.22
  
  $
  33.18
  
  $
  35.11
  
  $
  21.70
  
  $
  30.48NGLs
  
  $
  46.61
  
  $
  35.44
  
  $
  26.29
  
  $
  21.23
  
  $
  31.12  13 
   Natural Gas Netbacks ($ per Mcf)  Year Ended December 31, 2002FirstQuarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  YearSales price
  
  $
  3.04
  
  $
  3.93
  
  $
  3.37
  
  $
  4.99
  
  $
  3.87Hedging gains (costs)
  
  0.02
  
  (0.09
  )
  0.05
  
  (0.19
  )
  (0.06
  )Royalties
  
  (0.74
  )
  (0.94
  )
  (0.67
  )
  (1.07
  )
  (0.86
  )Operating costs(1)
  
  (0.68
  )
  (0.84
  )
  (0.76
  )
  (0.79
  )
  (0.77
  )Netback
  
  $
  1.64
  
  $
  2.06
  
  $
  1.99
  
  $
  2.94
  
  $
  2.18  Year Ended December 31, 2001FirstQuarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  YearSales price
  
  $
  8.59
  
  $
  5.81
  
  $
  3.43
  
  $
  3.01
  
  $
  4.91Hedging gains (costs)
  
  (0.21
  )
  0.01
  
  1.03
  
  1.51
  
  0.69Royalties
  
  (2.46
  )
  (1.60
  )
  (0.92
  )
  (0.39
  )
  (1.24
  )Operating costs(1)
  
  (0.77
  )
  (0.83
  )
  (0.82
  )
  (0.96
  )
  (0.85
  )Netback
  
  $
  5.15
  
  $
  3.39
  
  $
  2.72
  
  $
  3.17
  
  $
  3.51  
 Note: (1)Operating costs are expenses incurred in the operation of producing
properties and include items such as field staff costs, power, fuel, chemicals,
repairs and maintenance, property taxes, lease rentals, processing and treating
fees, overhead fees and other costs.  Quarterly Capital Expenditures  The ongoing capital expenditures of Enerplus are financed through the
issuance of additional Trust Units, bank borrowing, the withholdings of amounts
from cash distributions to unitholders and the use of working capital.  The following table summarizes Enerplus
capital expenditures in the categories and for the periods indicated.  Year Ended December 31, 2002First
  Quarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  Year(in thousands)Development drilling and completions
  
  $
  18,322
  
  $
  12,158
  
  $
  31,977
  
  $
  27,412
  
  $
  89,869Plant and facilities
  
  10,563
  
  9,278
  
  12,842
  
  14,151
  
  46,834Office and other expenditures
  
  2,093
  
  2,510
  
  1,297
  
  3,513
  
  9,413Subtotal
  
  30,978
  
  23,946
  
  46,116
  
  45,076
  
  146,116Property acquisitions
  
  21,205
  
  1,705
  
  25,360
  
  12,311
  
  60,581Corporate acquisitions
  
  
  
  
  
  
  
  158,063
  
  158,063Property dispositions
  
  (218
  )
  (1,920
  )
  (308
  )
  (612
  )
  (3,058
  )Net capital expenditures
  
  $
  51,965
  
  $
  23,731
  
  $
  71,168
  
  $
  214,838
  
  $
  361,702  Year Ended December 31, 2001FirstQuarter
  
  SecondQuarter
  
  ThirdQuarter
  
  FourthQuarter
  
  Total for
  Year(in thousands)Development drilling and completions
  
  $
  8,529
  
  $
  19,218
  
  $
  25,941
  
  $
  29,316
  
  $
  83,004Plant and facilities
  
  14,006
  
  6,981
  
  15,190
  
  17,417
  
  53,594Office and other expenditures
  
  1,448
  
  2,899
  
  771
  
  1,564
  
  6,682Subtotal
  
  23,983
  
  29,098
  
  41,902
  
  48,297
  
  143,280Property acquisitions
  
  367
  
  2,388
  
  57,214
  
  17,463
  
  77,432Corporate acquisitions
  
  32,420
  
  689,784
  
  
  
  
  
  722,204Property dispositions
  
  (9,427
  )
  (10,548
  )
  (34,826
  )
  (13,695
  )
  (68,496
  )Net capital expenditures
  
  $
  47,343
  
  $
  710,722
  
  $
  64,290
  
  $
  52,065
  
  $
  874,420  14 
   Exploration
and Development  The primary operational focus of Enerplus is to pursue growth
opportunities through the development of existing reserves, the monetization of
Enerplus exploratory lands and the acquisition of new properties.  High risk exploration plays, as well as
Enerplus undeveloped acreage, will continue to be farmed out, sold, or
exchanged for producing properties with upside potential.  Development efforts will concentrate on
optimizing production from existing and new reserves, and developing new
properties in a cost effective manner. 
Enerplus will continue its ongoing property rationalization program and
any sale proceeds may be used to acquire interests in core areas or new
prospects with exploitation opportunities.  Marketing
Arrangements  No individual customer accounts for more than 10% of Enerplus crude
oil, NGLs or natural gas production.  Crude oil and NGLs  Enerplus crude oil and NGLs production are 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 $34.37/Bbl for its crude oil and $25.68/Bbl for its NGLs for the
year ended December 31, 2002, compared to $30.48/Bbl for crude oil and
$31.12/Bbl of NGLs for the year ended December 31, 2001.  Natural Gas  In marketing its natural gas production, Enerplus efforts are directed
to achieve a mix of contracts, customers and geographic markets.  Enerplus percentage of 2002 revenues
attributable to natural gas, before hedging, was 47% compared to 53% in 2001
(notwithstanding that natural gas represented approximately 55% of Enerplus
total production in both 2001 and 2002). The average price received by
Enerplus, before hedging, for its natural gas in 2002 was $3.87/Mcf compared to
$4.91/Mcf in the year ended December 31, 2001.  Future Commitments  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 instruments is contained in Note 7 to Enerplus audited
annual consolidated financial statements for the year ended December 31, 2002
and under the heading Pricing and Price Risk Management in the Funds
management discussion and analysis for the year ended December 31, 2002 which
is contained on pages42 to 44 of the Funds 2002 Annual Report,
both of which are incorporated herein by reference.  Enerplus has firm commitments for gathering, processing and
transmission services that require Enerplus to deliver certain minimum
quantities of crude oil and NGLs and natural gas to third parties or pay the
corresponding tariffs.  With respect to
natural gas, Enerplus has contracted to transport 10 MMcf/day of natural gas
into Chicago on the Foothills and Northern Border pipelines until October 31,
2008.  It has also agreed to transport 5
MMcf/day to Marshfield, Illinois on the TransCanada and Viking pipelines until
October 31, 2008.  In addition, Enerplus
has pipeline commitments to transport 5 MMcf/day into Chicago on the Alliance
Pipeline until October 31, 2015.  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 existing environmental standards and regulations and
has included appropriate amounts in its capital expenditure budget to continue
to meet  15 
   its environmental obligations. The costs incurred by Enerplus for
compliance with environmental matters and site restoration costs amounted to
approximately 3% of the total development expenditures incurred by Enerplus in
2002.  Since the environmental standards
and regulations to which Enerplus is subject (including the newly ratified
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.  OIL AND NATURAL GAS RESERVES  Sproule Associates Limited, a firm of independent petroleum engineers,
has evaluated Enerplus major properties which comprise approximately 86% of
Enerplus proven developed producing crude oil and gas reserve value discounted
at 12%, and 84% of Enerplus proven plus probable oil and gas reserves value
discounted at 12%.  Enerplus has
evaluated the balance of the properties using similar evaluation parameters,
including the same escalated price forecasts utilized by Sproule.  The constant price cases contained herein
were extracted from a separate report prepared by Sproule dated February 10,
2003, which was based upon the escalated case Sproule Report.  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 gross production
and reserve volumes, which are prior to the deduction of royalties and similar
payments.  In the United States,
production and reserve volumes are reported after deducting these amounts.  The Canadian practice of using escalating
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 using Established
Reserves, which include Proven Reserves and the Probable Reserves portion that
has been reduced by a risk factor of 50%. 
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 January 1, 2003, of Enerplus crude
oil, NGLs and natural gas reserves attributable to Enerplus properties and the
present worth value of the estimated future net cash flows associated with such
reserves, based on escalated and constant price and cost assumptions and do not
give effect to any commodity price hedging contracts to which Enerplus is a
party. The tables summarize the data contained in the evaluations and as a
result may contain slightly different numbers than the evaluations due to
rounding. All
future cash flows are stated prior to provision for income taxes, interest,
general and administrative expenses and after deduction of royalties and
estimated future capital expenditures. 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. The probable additional reserve
volumes and the present value of estimated future cash flows from such reserves
as shown in the tables have been reduced by a factor of 50% to account for
risk.  16 
   Oil and Natural Gas Reserves
and Present Value of Estimated Future Cash Flows Including ARTC Based on Escalated Price
Assumptions(11)  Working Interest Reserves(1)
  
  Present Value of Estimated Future Net Cash Flow,$ 000 Discounted at Rates of:Gross
  
  NetOil
  
  Gas
  
  NGLs
  
  Oil
  
  Gas
  
  NGLsMbbls
  
  MMcf
  
  Mbbls
  
  Mbbls
  
  MMcf
  
  Mbbls
  
  0%
  
  10%
  
  15%
  
  20%Proven Reserves(2)Developed Producing(3)(4)
  
  94,901
  
  787,333
  
  14,020
  
  86,023
  
  628,699
  
  9,803
  
  3,864,497
  
  1,805,685
  
  1,500,461
  
  1,301,190Developed
  Non-Producing(3)(5)
  
  720
  
  23,306
  
  372
  
  626
  
  18,669
  
  258
  
  80,246
  
  31,542
  
  24,147
  
  19,578Undeveloped (6)
  
  9,626
  
  191,274
  
  1,643
  
  8,143
  
  158,149
  
  1,248
  
  490,135
  
  193,461
  
  133,143
  
  94,155Total Proven Reserves
  
  105,247
  
  1,001,913
  
  16,036
  
  94,792
  
  805,517
  
  11,309
  
  4,434,879
  
  2,030,688
  
  1,657,751
  
  1,414,922Probable Reserves at 50%
  (7)
  
  16,725
  
  138,789
  
  2,318
  
  14,506
  
  114,034
  
  1,631
  
  660,362
  
  163,301
  
  110,063
  
  80,123Established Reserves
  
  121,972
  
  1,140,702
  
  18,354
  
  109,298
  
  919,551
  
  12,940
  
  5,095,241
  
  2,193,989
  
  1,767,814
  
  1,495,045  Oil and Natural Gas Reserves
and Present Value of Estimated Future Cash Flows Including ARTC Based on Constant Price
Assumptions(12)  Working Interest Reserves(1)
  
  Present Value of Estimated Future Net Cash Flow,$  000
  Discounted at Rates of:Gross
  
  NetOil
  
  Gas
  
  NGLs
  
  Oil
  
  Gas
  
  NGLsMbbls
  
  MMcf
  
  Mbbls
  
  Mbbls
  
  MMcf
  
  Mbbls
  
  0%
  
  10%
  
  15%
  
  20%Proven Reserves(2)Developed Producing(3)(4)
  
  99,547
  
  809,546
  
  14,711
  
  90,118
  
  645,134
  
  10,267
  
  5,452,264
  
  2,635,744
  
  2,171,552
  
  1,864,942Developed
  Non-Producing(3)(5)
  
  736
  
  23,319
  
  372
  
  635
  
  18,665
  
  257
  
  106,775
  
  44,842
  
  34,531
  
  27,992Undeveloped (6)
  
  9,744
  
  193,148
  
  1,646
  
  8,186
  
  159,474
  
  1,249
  
  792,389
  
  352,078
  
  259,486
  
  198,236Total Proven Reserves
  
  110,027
  
  1,026,013
  
  16,729
  
  98,939
  
  823,273
  
  11,773
  
  6,351,427
  
  3,032,664
  
  2,465,569
  
  2,091,170Probable Reserves at
  50%(7)
  
  18,012
  
  141,145
  
  2,325
  
  15,473
  
  115,643
  
  1,632
  
  889,509
  
  255,792
  
  179,912
  
  135,592Established Reserves
  
  128,039
  
  1,167,158
  
  19,054
  
  114,412
  
  938,916
  
  13,405
  
  7,240,936
  
  3,288,456
  
  2,645,481
  
  2,226,762  
 Notes:  (1)Gross Reserves are the remaining reserves owned by Enerplus, before
deduction of any royalties.  Net
Reserves are the gross remaining reserves of the properties in which Enerplus
has an interest, less all royalties and interests owned by others. (2)Proven Reserves are those quantities of oil, natural gas and natural
gas by-products, which, upon analysis of geologic and engineering data, appear
with a high degree of certainty to be recoverable at commercial rates in the
future from known oil and natural gas reservoirs under current economic and
operating conditions for reserves based on constant price and cost assumptions,
and presently anticipated economic and operating conditions for the reserves
based on escalated price and cost assumptions. 
There is relatively little risk with these reserves. (3)Proven Developed Reserves are Proven Reserves which can be expected to
be recovered through existing wells with existing equipment and operating
methods. (4)Proven Developed Producing Reserves are Proven Reserves which are
presently being produced from completion intervals open for production in
existing wells.  As at January 1, 2003,
these reserves were on production and represent approximately 78% of Enerplus
total gross proven and risked probable oil and NGLs reserves and 69% of
Enerplus total gross proven and risked probable natural gas reserves. (5)Proven Developed Non-producing Reserves are Proven Reserves which are
currently not being produced but do exist in completed intervals but not
producing in existing wells, behind casing in existing wells or at minor depths
below the present bottom of existing wells. 
These Proven Reserves are expected to be produced through the existing
wells in the predictable future.  These
reserves are classified as Proven Developed Reserves since the cost of making
such reserves available for production is relatively small compared to the cost
of a new well. (6)Proven Undeveloped Reserves are Proven Reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where
relatively major expenditures are required for the completion of these wells or
for the installation of processing and gathering facilities prior to the
production of these reserves.  Reserves
on undrilled acreage are limited to those drilling units offsetting productive
wells that are reasonably certain of production when drilled. (7)Probable Reserves are those reserves which may be recoverable as a
result of the beneficial effects which may be derived from the future
institution of some form of pressure maintenance or other secondary recovery
method, or as a result of a more favourable performance of the existing
recovery mechanism than that which would be deemed proven at the present time,
or those reserves which may reasonably be assumed to exist because of
geophysical or geological indications and drilling done in regions which
contain proven reserves.  Probable
reserve values for the petroleum and natural gas properties and the future net
cash flow from probable reserves have been discounted by a factor of 50% to
account for the risk associated with the probability of obtaining production
from such reserves. (8)Includes the ARTC based on current legislation in place on January 1,
2003. (9)Natural gas reserves are reported at a base pressure of 14.65 pounds per
square inch and a base temperature of 60o F. (10)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  17 
   transportation to reflect the actual price to be received.  The natural gas prices were 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. (11)The
escalated price and cost case assumes the continuance of current laws and
regulations, and any increase in selling prices also takes inflation into
account.  The product price forecasts
used are as follows:  WTICushingOklahoma
  
  Edmonton
  
  Natural Gas Liquids
  
  Natural GasPar Price
  
  Plant Gate Ethane
  
  Edmonton
  
  Plant GateYear
  
  40°API
  
  
  Propane
  
  Butane
  
  Pentanes
  
  Alberta
  
  Sask.
  
  B.C.(US$/Bbl)
  
  ($/Bbl)
  
  ($/Bbl)
  
  ($Bbl)
  
  ($/Bbl)
  
  ($/Bbl)
  
  ($/MMBTU)
  
  ($/MMBTU)
  
  ($/MMBTU)2003
  
  25.99
  
  38.43
  
  16.32
  
  21.53
  
  24.35
  
  39.36
  
  5.72
  
  5.89
  
  5.942004
  
  23.60
  
  34.82
  
  14.92
  
  19.50
  
  22.06
  
  35.66
  
  5.21
  
  5.38
  
  5.432005
  
  21.63
  
  32.22
  
  13.22
  
  18.05
  
  20.42
  
  33.00
  
  4.60
  
  4.77
  
  4.822006
  
  21.96
  
  32.78
  
  12.34
  
  18.36
  
  20.77
  
  33.57
  
  4.27
  
  4.45
  
  4.482007
  
  22.29
  
  33.90
  
  12.77
  
  18.99
  
  21.48
  
  34.72
  
  4.42
  
  4.61
  
  4.662008
  
  22.62
  
  34.42
  
  12.95
  
  19.28
  
  21.81
  
  35.25
  
  4.48
  
  4.67
  
  4.742009
  
  22.96
  
  35.58
  
  13.45
  
  19.93
  
  22.54
  
  36.44
  
  4.67
  
  4.86
  
  4.932010
  
  23.31
  
  36.13
  
  13.70
  
  20.24
  
  22.89
  
  37.00
  
  4.75
  
  4.94
  
  5.012011
  
  23.66
  
  36.69
  
  13.95
  
  20.55
  
  23.24
  
  37.57
  
  4.84
  
  5.03
  
  5.102012
  
  24.01
  
  37.26
  
  14.20
  
  20.87
  
  23.60
  
  38.16
  
  4.94
  
  5.13
  
  5.202013
  
  24.37
  
  37.83
  
  14.46
  
  21.19
  
  23.97
  
  38.76
  
  5.03
  
  5.22
  
  5.292014
  
  24.74
  
  38.42
  
  14.72
  
  21.52
  
  24.34
  
  39.35
  
  5.12
  
  5.31
  
  5.38 Escalation Rate of 1.5% thereafter  (12)The
constant price and cost case assumes the continuance of product prices at
January 1, 2003 and operating costs projected for 2003,  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
annual revenue to be received from the production of the reserves was based on
the following prices:  Oil
  
  Edmonton Par Price 40° API ($/Bbl)
  
  $
  48.24Natural Gas:
  
  Alberta ($/MMBTU)
  
  $
  6.02Saskatchewan ($/MMBTU)
  
  $
  6.13British Columbia ($/MMBTU)
  
  $
  6.10Natural Gas Liquids:
  
  Ethane ($/Bbl)
  
  $
  17.85Propane ($/Bbl)
  
  $
  29.21Butanes ($/Bbl)
  
  $
  33.21Pentanes Plus ($/Bbl)
  
  $
  46.30
  (13)Capital
expenditures required to achieve the future net revenue attributable to Proven
Reserves in the escalated price and cost case were estimated to be $207
million, of which $88 million is required in 2003 and $59 million is required
in 2004.  Capital expenditures required
to achieve the future net revenue attributable to Probable Reserves in the
escalated price and cost case are estimated to be $105 million, of which $37
million is required in 2003 and $18 million is required in 2004. (14)Capital
expenditures required to achieve the future net revenue attributable to Proven
Reserves in the constant price and cost case are estimated to be $203 million
of which $88 million is required in 2003 and $59 million is required in
2004.  Capital expenditures required to
achieve the future net revenue attributable to Probable Reserves in the
constant price and cost case are estimated to be $103 million, of which $37
million is required in 2003 and $17 million is required in 2004. (15)Estimated
Future Net Production Revenue has been calculated before deduction of income
tax.  The present worth of estimated Future
Net Production Revenue is not to be construed as fair market value.  18 
   Estimated
Future Net Pre-Tax Cash Flows Established Reserves(1) Escalating Cost and Price Case ($000s except for production)  Year
  
  Annual
  Production(MBOE)
  
  CompanyInterestRevenue(2)
  
  RoyaltyBurdens
  
  Net Revenue
  After Royalty
  Burdens
  
  Operating
  Expenses
  
  Net
  Production
  Revenue(3)
  
  Net
  Capital
  Investment
  
  Net Cash
  Flow Before
  Income
  Taxes(4)(5)2003
  
  25,295
  
  851,444
  
  185,496
  
  665,948
  
  145,811
  
  520,138
  
  107,317
  
  412,8212004
  
  24,928
  
  763,025
  
  159,998
  
  603,028
  
  150,070
  
  452,958
  
  69,856
  
  383,1022005
  
  22,968
  
  627,204
  
  122,976
  
  504,228
  
  148,434
  
  355,794
  
  45,132
  
  310,6632006
  
  20,580
  
  542,886
  
  101,778
  
  441,108
  
  143,744
  
  297,364
  
  25,131
  
  272,2342007
  
  18,512
  
  506,458
  
  92,576
  
  413,882
  
  140,146
  
  273,736
  
  8,144
  
  265,5922008
  
  16,528
  
  459,071
  
  81,725
  
  377,347
  
  133,432
  
  243,915
  
  7,420
  
  236,4952009
  
  14,776
  
  426,294
  
  74,607
  
  351,688
  
  125,831
  
  225,857
  
  4,784
  
  221,0742010
  
  13,337
  
  390,232
  
  67,607
  
  322,625
  
  117,951
  
  204,674
  
  3,612
  
  201,0622011
  
  12,037
  
  358,290
  
  61,043
  
  297,248
  
  111,808
  
  185,440
  
  3,287
  
  182,1542012
  
  10,834
  
  329,500
  
  55,506
  
  273,994
  
  105,229
  
  168,765
  
  4,062
  
  164,703Remaining
  
  150,646
  
  6,196,999
  
  769,198
  
  5,427,801
  
  2,859,542
  
  2,568,259
  
  122,916
  
  2,445,343TOTAL:
  
  330,442
  
  11,451,401
  
  1,772,507
  
  9,678,894
  
  4,181,996
  
  5,496,899
  
  401,659
  
  5,095,240  Cash Flow Before Income
Taxes(5)  Discounted to January 1, 2003
at: 10%:$2,193,989,000 15%:$1,767,814,000 20%:$1,495,045,000  
 Notes:  (1)Proven Reserves plus 50% Probable Reserves. (2)Includes working interest revenue, royalty interest revenue and third
party processing and other income. (3)Company interest revenue less royalty burdens and operating expenses. (4)Undiscounted. (5)Cash flow before income taxes is stated prior to interest, general and
administrative expenses and management fees.  Estimated Future Net Pre-Tax Cash Flows Established
Reserves(1) Constant Cost and Price Case ($000s except for production)  Year
  
  Annual
  Production(MBOE)
  
  CompanyInterestRevenue(2)
  
  RoyaltyBurdens
  
  Net Revenue
  After Royalty
  Burdens
  
  Operating
  Expenses
  
  Net
  Production
  Revenue(3)
  
  Net Capital
  Investment
  
  Net Cash
  Flow Before
  Income
  Taxes(4)(5)2003
  
  25,707
  
  974,960
  
  203,963
  
  770,997
  
  148,153
  
  622,844
  
  106,639
  
  516,2052004
  
  25,333
  
  957,907
  
  194,496
  
  763,411
  
  151,099
  
  612,312
  
  68,528
  
  543,7842005
  
  23,369
  
  881,372
  
  169,700
  
  711,672
  
  148,618
  
  563,054
  
  43,576
  
  519,4782006
  
  20,989
  
  790,429
  
  147,517
  
  642,912
  
  142,635
  
  500,277
  
  23,814
  
  476,4642007
  
  18,892
  
  710,556
  
  128,071
  
  582,485
  
  137,599
  
  444,886
  
  7,102
  
  437,7842008
  
  16,911
  
  635,771
  
  111,482
  
  524,289
  
  129,524
  
  394,765
  
  6,949
  
  387,8172009
  
  15,150
  
  568,596
  
  97,481
  
  471,115
  
  121,071
  
  350,044
  
  4,637
  
  345,4072010
  
  13,704
  
  512,598
  
  86,805
  
  425,793
  
  112,362
  
  313,431
  
  3,564
  
  309,8672011
  
  12,367
  
  462,023
  
  76,891
  
  385,132
  
  104,539
  
  280,593
  
  2,428
  
  278,1662012
  
  11,169
  
  418,582
  
  68,681
  
  349,901
  
  98,036
  
  251,865
  
  3,471
  
  248,394Remaining
  
  158,031
  
  5,957,991
  
  758,902
  
  5,199,089
  
  1,949,507
  
  3,249,582
  
  72,012
  
  3,177,570TOTAL:
  
  341,620
  
  12,870,782
  
  2,043,990
  
  10,826,792
  
  3,243,141
  
  7,583,651
  
  342,716
  
  7,240,936  Cash Flow Before Income
Taxes(5)  Discounted to January 1, 2003
at:  10%:$3,288,456,000 15%:$2,645,481,000 20%:$2,226,762,000  
 Notes: (1)Proven Reserves plus 50% Probable Reserves. (2)Includes working interest revenue, royalty interest revenue and third
party processing and other income. (3)Company interest revenue less royalty burdens and operating expenses. (4)Undiscounted. (5)Cash flow before income taxes is stated prior to interest, general and
administrative expenses and management fees.  19 
   INFORMATION RESPECTING ENERPLUS RESOURCES FUND  Operations
of Enerplus  Management Policies  The board of directors of EnerMark, as the publicly-elected body which
oversees the business and affairs of Enerplus, supervises the management of
Enerplus 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 lower-risk development of mature,
long-life oil and natural gas properties. 
Since Enerplus does not 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 asset or property acquisition (or disposition) with a value of
greater than $10 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.  To the extent its acquisitions include undeveloped properties, Enerplus
enters into farmout or swap agreements under which an exploration and
production company will explore and drill the undeveloped properties 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
its traditional lower-risk development activities, as discussed below.  Enerplus undertakes lower-risk 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
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 issuance of Trust Units and
internally-generated cash flow.  Environment and Safety  Enerplus is committed to its goal of conducting business in a safe and
environmentally responsible manner. 
Emphasis is focused on providing the best possible protection and safety
to employees, the public, stakeholders and the environment. Enerplus
comprehensive Environment and Safety (E&S) Management Program is
constantly reviewed and upgraded to meet this commitment.  In 2002, Enerplus registered its existing
E&S Management Program with the Canadian Association of Petroleum
Producers Environment, Health and Safety Stewardship Program at the Platinum
level, the highest attainable rating, which reflects Enerplus standing within
the industry.  20 
   Environment  Enerplus has evaluated its existing solution gas flares in each of
British Columbia, Alberta and Saskatchewan. 
All sites met or exceeded regulatory requirements.  However, Enerplus continues to evaluate its
operations to reduce or eliminate flaring.  Enerplus has also evaluated benzene emissions in its operations and by
the end of 2002 all sites met industry recommended criteria. Newly acquired
properties are added to both the flaring and benzene inventories and are  subject to ongoing assessment.  In order to prevent environmental damage from corrosion related
incidents, Enerplus continues to utilize its Corrosion Risk Management Program
throughout its operations. This helps identify properties where improvements
can have the largest positive impact and has resulted in pipeline replacements,
installation of pipeline liners and improved corrosion protection programs.  Safety  Enerplus Job Performance Management System (JPMS) is a comprehensive
approach to managing risk and worker competencies in Enerplus field
operations. JPMS is used to manage an employees or contractors progress and
competence and to ensure that hazardous tasks are carried out safely,
responsibly and effectively. This is a key component of Enerplus training
program.  In addition, Enerplus continues to promote its Loss Control Council, a
rotating team of experienced and knowledgeable employees consisting of both
field and office staff. This team conducts inspections of operated properties
each year, allowing for cross training between disciplines and sharing of
information between operating areas regarding best practices.  Compliance  Since acquisitions are an integral part of Enerplus business, a
thorough due diligence investigation is conducted on potential acquisitions to
ensure that they meet both regulatory and Enerplus requirements. A team that
includes both employees and third party consultants typically conducts site
inspections and file reviews prior to completing an acquisition. Potential
contamination and operational issues can be identified at this stage, which is
designed to protect Enerplus from purchasing properties with significant
liabilities. In 2002, investigations wereconducted in respect of several
acquisitions, including the Celsius acquisition, and no material environmental
or safety-related liabilities were noted.  As part of its ongoing due diligence program, Enerplus conducts both
internal (through its Loss Control Council) and third party site inspections at
selected operated and non-operated facilities, construction and drilling
projects each year.  In this way,
Enerplus ensures that its own operations, as well as the operations of its
partners in industry, meet regulatory and industry requirements for environment
and safety issues.  Enerplus also maintains an active abandonment and reclamation program
dedicated to decommissioning unneeded facilities and restoring these lease
sites to their original state as well as an active idle wellbore abandonment
program.  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.  21 
   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 these long-term debt arrangements
are contained in Note 2 of the Funds audited annual consolidated financial
statements for the year ended December 31, 2002 and under the heading
Liquidity and Capital Resources in Enerplus management discussion and
analysis, contained on pages 50 to 51 of the Funds 2002 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 distribution payments
that are made to the Fund by its operating subsidiaries, and therefore ahead of
distributions from the Fund to its unitholders.  See  - 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, 2002, Enerplus (including the personnel of EGEM who
devoted a significant portion of their time to the affairs of Enerplus)
employed a total of 445 persons.  Description
of the Trust Units and the Trust Indenture  General  The Fund was created, and the Trust Units are issued, pursuant to the
Trust Indenture.  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 all Trust Units carry equal voting
rights 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 rights, warrants or options
to subscribe for 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 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 Trust Indenture, among other things, provides for 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 and Voting and Amendments to the Trust Indenture below.  22 
   The following is a summary of certain provisions of the Trust
Indenture. For a complete description, reference should be made to the Trust
Indenture, copies of which may be viewed at the offices of, or obtained from,
the Trustee. See Reporting to Unitholders.  The Trustee  CIBC Mellon Trust Company is the trustee of the Fund. The Trustee
possesses and may exercise all rights, powers and privileges pertaining to the
ownership of the Funds assets to the same extent as an individual or
beneficial owner might. Additionally, the Trustee is responsible for, among
other things, (i) effecting payment of distributions to the Funds unitholders;
(ii) maintaining records and providing timely reports to unitholders, and (iii)
performing functions related to supervision and activities of the Fund. The
Trustee may also delegate any or all of its management or administrative powers
and, pursuant to the Trust Indenture and the Management Agreement, has retained
EnerMark to effect the actual administration of its duties under the Trust
Indenture.  However, the Trustee
continues to ultimately be responsible for the performance of these duties.  The Trustee shall be removed by notice in writing delivered by EnerMark
to the Trustee if the Trustee fails to meet certain criteria stated within the
Trust Indenture or with the approval of at least 66 2/3% of the votes cast at a
meeting of unitholders called for that purpose.  The Trustee or any successor may resign upon 60 days notice to
EnerMark.  Such resignation or removal
shall become effective upon the acceptance of appointment by a successor
trustee.  If the Trustee is removed by
EnerMark, EnerMark may appoint a successor trustee. If the Trustee resigns or
is removed by unitholders, its successor must be either appointed by EnerMark
or the unitholders.  If a successor
trustee does not accept its appointment as trustee, a court may appoint the
successor trustee.  The Trust Indenture provides that the Trustee shall exercise the powers
and discharge the duties of its office honestly, in good faith and in the best
interests of the Fund and its unitholders and shall exercise the degree of
care, diligence and skill that a reasonably prudent person would exercise in
comparable circumstances.  The Trustee will not be liable for any action taken in good faith in
reliance on prima
facie properly executed documents or for the disposition of monies
or securities, nor shall it be liable or responsible in any way for
depreciation or loss incurred by reason of the sale of any security or for any
inaccuracy in any advice or action of EnerMark or any authorized delegate.  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 out of the
assets of the Fund for any taxes or other governmental charges 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 EnerMark the fees that
may be agreed upon in writing by EnerMark and the Trustee, and is entitled to
be reimbursed by EnerMark for its expenses incurred in acting as trustee.  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 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, 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.  23 
   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 95% and 99% royalty interests issued to
the Fund by EnerMark and ERC.  The Fund
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 and ERC 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. 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 the Trustees discretion, which has been
delegated to EnerMark under the Management Agreement.  Under the Trust Indenture, the Trustee has the authority to determine
the timing and the number of distribution record dates within the year. Under
the Management Agreement, the Trustee has delegated this authority to EnerMark.
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 the
Trustee (as delegated to 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
or within 30 days of the distribution record date. The Trust Indenture provides
that the Trustee may declare payable to the unitholders on a pro rata basis all
or any part of the distributable income and net realized capital gains of the
Fund for that period ending on the distribution record date to the extent that
cash flow was not previously declared payable. The authority to determine the
amount of distributable income and net realized capital gains, if any, that
will be paid on a given distribution date, and to administer these payments,
has been delegated by the Trustee 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 unitholders.  Meetings and Voting  At all meetings of the Funds unitholders, each holder is entitled to
one vote in respect of each Trust Unit held. 
Meetings of the unitholders may be called on not less than 21 days and
not more than 50 days notice and may be called at any time by the Trustee and
shall be called by the Trustee and held annually or upon written request of
unitholders holding in the aggregate not less than 20% of the Trust Units.  All activities necessary to organize any
such meeting will be undertaken by EnerMark on behalf of the Trustee.  24 
   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.  Under the Trust Indenture and the Governance Agreement, the Funds
unitholders are entitled to nominate the directors of EnerMark and to nominate
the auditors of the Fund.  Certain
matters, such as the removal or appointment of the Trustee, making material
amendments to the Trust Indenture, the termination of the Fund or the sale of
all or substantially all of the property of the Fund, must be approved by at
least 66 2/3% of the votes cast at a meeting of unitholders.  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.  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, 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  (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.  Management of the Fund  The Trust Indenture provides the Trustee with certain powers and
authorities with respect to the Fund and its assets.  See Description of the Trust Units and The Trust Indenture - The
Trustee above.  Additionally, the Trust
Indenture provides that the Trustee may grant or delegate such authority as the
Trustee may in its sole discretion deem necessary or advisable to effect the
actual administration of the Fund.  The
Trustee has delegated to EnerMark the supervision of the management and affairs
of the Fund, including the responsibility for significant administrative and
operational decisions.  In particular,
the Trustee has delegated to EnerMark the responsibility for, among other things,
all issuances and offerings of Trust Units, merger and acquisition activity
relating to Enerplus, the amendment of material contracts to which the Fund is
a party, borrowings by Enerplus, voting of securities held by the Fund and
approval of the Funds financial statements. 
Additionally, following completion of the Internalization Transaction,  25 
   EnerMark has the responsibility to manage the operations, business and
affairs of Enerplus as a whole.  See
Information Respecting Enerplus Resources Fund - Management and Corporate
Governance.  Termination of the Fund  The unitholders may vote by extraordinary resolution (i.e., 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 to redeem Trust Units.  The
quorum requirement for such a meeting is at least 20% of the issued and
outstanding Trust Units represented in person or by proxy.  Upon being required to commence to wind up the affairs of the Fund, the
Trustee will give notice to the unitholders designating the time at which
unitholders may surrender their Trust Units for cancellation and the date at
which the register of the Fund shall be closed.  After the date on which the Trustee is required to commence to wind up
the affairs of the Fund, the Trustee will generally carry on no activities
except for the purpose of winding up the affairs of the Fund and, for this
purpose, the Trustee will continue to be vested with and may exercise all or
any of the powers conferred upon the Trustee under the Trust Indenture.  Reporting to Unitholders  The accounts of the Fund are audited at least annually by an
independent recognized firm of chartered accountants selected by the
unitholders, and the financial statements of the Fund, together with the report
of the auditors, are mailed by the Fund to unitholders within appropriate
regulatory time periods in each calendar year. 
The fiscal year-end of the Fund is December 31.  The Trust Indenture provides that a unitholder has the right, upon
payment of reasonable production costs, to obtain a copy of the Trust Indenture
and the right to inspect and, on payment of the reasonable charges of the
registrar therefor, to obtain a list of the registered holders of the Trust
Units for purposes connected with the Fund.  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;  26 
   (c)ensuring
that such additional protection is provided for the interests of unitholders as
the Trustee or the board of directors of 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 in no way prejudices
any of the rights of the unitholders or the Trustee; and  (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 Trustee and of the unitholders
are not prejudiced thereby.  Description
of the Royalty
Agreements and Subordinated Note  The Funds primary sources of net cash flow are: (i) payments received
from 95% and 99% net royalty interests 
issued to the Fund by EnerMark and ERC, 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
and ERC to the Fund and the subordinated debt issued by EnerMark to the Fund.  Royalty Agreements  Pursuant to separate royalty agreements between the Fund and each of
EnerMark and ERC, EnerMark and ERC have granted to the Fund a 95% 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 and ERC 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 to secure loans by EnerMark and ERC. Such security interests
may rank ahead of the royalty interests of the Fund.  Further, both EnerMark and ERC 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 and ERC are subordinated and will rank junior
to the indebtedness of EnerMark to its lenders and the holders of its senior
unsecured notes.  Pursuant to each royalty agreement, EnerMark and ERC have the right to
dispose of properties and the associated royalties if they believe that it is
in the best interests of unitholders to do so. The royalty agreements continue
in  27 
   force for as long as EnerMark or ERC has an interest in the properties
covered by their respective 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.  Subordinated Note  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 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.  Management
and Corporate Governance  General  Under the terms of the Trust Indenture, the Trustee is given broad
powers and authorities over the administration and management of the Fund.
Pursuant to the Trust Indenture and the Management Agreement, the Trustee has
delegated to EnerMark the supervision of the management of the business and
affairs of the Fund. Among other things, the board of directors of EnerMark is
given responsibility for all matters relating to offerings of securities of the
Fund, take-over bids or similar transactions involving the Fund or its
subsidiaries, the terms, amendment or execution of material contracts
(including the royalty agreements, the Management Agreement and the Governance
Agreement) on behalf of the Fund, the voting of securities held by the Fund
(including the shares of EnerMark), the redemption of Trust Units, any
borrowings or acquisitions made by the Fund or its subsidiaries and the
approval of the Funds public disclosure documents.  Pursuant to the Trust Indenture and in accordance with the Management
Agreement, the Trustee has retained and delegated certain authority to EnerMark
to provide comprehensive management services to and administer and manage the
day to day operations of the Fund and its operating subsidiaries, including:
(i) determining the total distributions owing to unitholders, (ii) providing
investor relations services to the Fund; (iii) providing unitholders with
financial reports and tax information relating to the Fund; (iv) calling,
holding and distributing materials in respect of meetings of unitholders; and
(v) determining the timing and terms of future offerings, issuances and
repurchases of Trust Units or other securities of the Fund.  Prior to the Internalization Transaction,
EGEM provided these services to Enerplus, subject to the supervision of the
board of directors of EnerMark, pursuant to the Management Agreement.  Governance Agreement  The Fund, as the sole shareholder of EnerMark, is entitled to elect the
directors of EnerMark, and under the terms of the Governance Agreement, must do
so in accordance with a vote of the Funds unitholders. Following those
nominations, the Fund and EnerMark will facilitate the election of those
persons to EnerMarks board of directors. The Governance Agreement also
provides that the boards of directors of EnerMark and its wholly-owned
subsidiary, ERC, are to be identical, and that any dividends received by
EnerMark from ERC must immediately be paid by EnerMark to the Fund.  28 
   Any person who subsequently becomes an owner of any shares of EnerMark
or ERC will be bound by the provisions of the Governance Agreement, and the
Governance Agreement may only be terminated, cancelled or amended in writing by
the parties to the agreement.  The
Trustee is to act in accordance with the direction of the board of directors of
EnerMark with respect to such matters.  Corporate Governance  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 Statement of Corporate Governance Practices on
pages 85 to 89 of the Funds 2002 Annual Report and under the heading
Statement of Corporate Governance Practices in the Funds information
circular and proxy statement dated March 10, 2003.  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  The amount available to the Fund to pay distributions depends on the
level of net cash flow received by the Fund from its operating subsidiaries
pursuant to the royalty agreements and as interest, principal, dividend and
distribution payments.  Distributions
for a period generally represent net cash flow of the operating subsidiaries
from the period approximately two months prior to the period in which the
distribution is made.  The amount of cash flow paid to the Fund is, in part, subject to the
discretion of the board of directors of EnerMark since it must be determined
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 5% and 20% of the total annual cash flow.  For the year ended December 31, 2002,
approximately 15% of the cash available for distribution was retained for debt
repayment.  29 
   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 completion of the Merger on June 21, 2001.  Month of Record
  and Payment Date
  
  Cash
  Distribution Per Trust Unit2003
  
  2002
  
  2001January(1)
  
  $0.30
  
  $0.30
  
  N/AFebruary
  
  $0.32
  
  $0.25
  
  N/AMarch
  
  $0.35
  
  $0.20
  
  N/AApril
  
  $0.35
  
  $0.20
  
  N/AMay
  
  $0.37
  
  $0.28
  
  N/AJune
  
  
  
  $0.28
  
  N/AJuly
  
  
  
  $0.28
  
  $0.48August
  
  
  
  $0.28
  
  $0.50September
  
  
  
  $0.28
  
  $0.45October
  
  
  
  $0.30
  
  $0.40November
  
  
  
  $0.30
  
  $0.40December
  
  
  
  $0.30
  
  $0.35  
 Note: (1)           The record date for
the distribution was December 31 of the prior year.  The
historical distribution payments described above may not be reflective of
future distribution payments, which will be subject to review by the board of
directors of EnerMark taking into account the prevailing financial
circumstances of the Fund at the relevant time.  See Risk Factors.  INDUSTRY CONDITIONS  The oil and natural gas industry is subject to extensive controls and
regulation imposed by various levels of government. Although we do not expect
that these controls and regulation will affect our operations in a manner
materially different than they would affect other Canadian oil and gas
companies 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 we are unable to predict what additional
legislation or amendments may be enacted.  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. Such
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. 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 National
Energy Board and the issue of such a licence requires the approval of the
Governor in Council.  30 
   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
supply/demand balance and other contractual terms.  Natural gas exported from Canada is subject to regulation by the
National Energy Board 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 National
Energy Board 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 order of the
National Energy Board. 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 National Energy Board 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  On January 1, 1994, the North American Free Trade Agreement among the
governments of Canada, the U.S. and Mexico became effective. 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; or (iii) disrupt normal channels of supply. All three countries are
prohibited from imposing minimum export or import price requirements and,
except as permitted in enforcement of countervailing and antidumping orders and
undertakings, minimum or maximum import price requirements.  The North American Free Trade Agreement contemplates the reduction of
Mexican restrictive trade practices in the energy sector and prohibits
discriminatory border restrictions and export taxes.  The North American Free Trade Agreement 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.  Provincial
Royalties and Incentives  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 probability of oil and natural gas production.
Royalties payable on production from lands other than Crown lands are
determined by negotiations between the freehold mineral owner and the lessee,
although production from such lands is also subject to certain provincial taxes
and royalties. Crown royalties are determined by governmental regulation and
are generally calculated as a percentage of the value of the gross production,
and the rate of royalties payable generally depends in part on prescribed
reference prices, well productivity, geographical location and field discovery
date.  From time to time, the federal and provincial governments in Canada
have established incentive programs which have included royalty rate
reductions, 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. Oil and natural gas royalty
holidays and reductions for specific wells will reduce the amount of Crown royalties
paid by us to the provincial governments.  On October 13, 1992, the government of Alberta implemented major
changes to its royalty structure and created incentives for exploring and
developing oil and natural gas reserves. The incentives created include: (i) a
one year  31 
   royalty holiday on new oil discovered on or after October 1, 1992; (ii)
incentives by way of royalty holidays and reduced royalties on reactivated, low
productivity, vertical re-entry and horizontal wells; (iii) introduction of
separate par pricing for light/medium and heavy oil; and (iv) a modification of
the royalty formula structure through the implementation of a third tier
royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered
after September 30, 1992. The new oil royalty reserved to the Crown has a base
rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown
has a base rate of 10% and a rate cap of 35%.  In Alberta, the royalty reserved to the Crown in respect of natural gas
production, subject to various incentives, is between 15% and 30%, in the case
of new gas, and between 15% and 35%, in the case of old gas, depending upon a
prescribed or corporate average reference price. Natural gas produced from
qualifying exploratory 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 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 wells.  In Alberta, certain producers of oil or natural gas are also entitled
to a credit against the royalties payable to the Alberta Crown by virtue of the
ARTC program. The ARTC credit program is based on a price-sensitive formula,
and the ARTC program rate varies between 75%, at prices for oil below $100 per
cubic meter, and 25%, at prices above $210 per cubic meter. The ARTC program
rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable
for each producer or associated group of producers. Crown royalties on
production from producing properties acquired from companies claiming maximum
entitlement to the ARTC program will generally not be eligible for the ARTC
program. The ARTC program rate is established quarterly based on the average
par price, as determined by the Alberta Department of Energy for the
previous quarterly period.  In British Columbia, the amount payable as a royalty in respect of oil
depends on the vintage of the oil (whether it was produced from a pool
discovered before or after October 31, 1975), the quantity of oil produced in a
month and the value of the oil. 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. Natural gas produced in association with oil has a
minimum royalty of 8% while the royalty in respect of other natural gas may not
be less than 15%.  Effective October 1, 2002, the government of Saskatchewan revised its
fiscal regime for the oil and gas industry. Some royalties on wells existing as
of that date will remain unchanged and will therefore be subject to various
periods of royalty/tax deduction. The changes include new lower royalty and tax
structures applicable to both oil, natural gas and associated natural gas
(natural gas produced from oil wells), a new system of volume incentives and a
reduced corporation capital tax resource surcharge rate.  The new fiscal regime for the Saskatchewan oil and gas industry
provides an incentive to encourage exploration and development through a
revised royalty/tax structure for oil and natural gas wells with a finished
drilling date on or after October 1, 2002 or incremental oil production due to a
new or expanded waterflood project with a commencement date on or after October
1, 2002. This fourth tier Crown royalty rate, applicable to both oil and
natural gas, is price sensitive and ranges from a minimum 5% at a base price to
a maximum of 30% at a price above the base price. A fourth tier freehold tax
structure, calculated by subtracting a production tax factor of 12.5 percentage
points from the corresponding Crown royalty rates, has also been created which
is applicable to conventional oil, incremental oil from new or expanded
waterfloods and natural gas. The fourth tier royalty/tax structure is also
applicable in respect of associated natural gas that is gathered for use or
sale which is produced either from oil wells with a finished drilling date on
or after October 1, 2002 and oil wells with a finished drilling date prior to
October 1, 2002, where the individual oil well has a gas-oil production ratio
in any month of more than 3,500 cubic metres of natural gas per cubic metre of
oil. In addition, volume-based royalty/tax reduction incentives have been
changed such that a maximum royalty of 2.5% now applies to various volumes of
both oil and natural gas, depending on the depth and nature of the well (up to
16,000 cubic metres of oil in the case of deep exploratory wells and 25,000
cubic metres of natural gas produced from exploratory wells). The royalty/tax
category with respect to re-entry and short sectional horizontal oil wells has
been eliminated such that all horizontal oil wells with a finished drilling
date on or after October 1, 2002 will receive fourth tier royalty/tax rates and
incentive volumes. Further  32 
   changes include the reduction of the corporation capital tax resource
surcharge rate from 3.6% to 2.0% and the expansion of the deep oil well
definition to include oil wells producing from a zone deeper than 1,700 meters
provided that the zone is within a geological system deposited during the
Mississippian Period or earlier or from a zone that was deposited before the
Bakken zone regardless of depth.  Oil and natural gas royalty holidays and reductions for specific wells
reduce the amount of Crown royalties paid by Enerplus to the provincial
governments. The ARTC program provides a rebate on Alberta Crown royalties paid
in respect of eligible producing properties. These incentives result in
increased net income and funds from our operations.  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 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 Alberta
Environmental Protection and Enhancement Act, which imposes certain
environmental responsibilities on oil and natural gas operators in Alberta and
imposes penalties for violations. In Saskatchewan, environmental compliance is
governed by the Environmental Management  and Protection Act (Saskatchewan). In
British Columbia, energy projects may be subject to review pursuant to the
provisions of the Environmental Assessment Act (British Columbia). The Environmental
Assessment Act (British Columbia) rolls the previous processes for
the review of major energy projects into a single environmental assessment
process which 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 federal government has not
released details of any implementation plan which could result in increased
operating costs and capital expenditures, it has stated that it intends to
limit the emission reduction targets for the industry.  Enerplus believes that it is in material compliance with applicable
environmental laws and regulations and is committed to meeting its
responsibilities to protect the environment wherever it operates.  Enerplus intends to  continue to take all steps necessary to
comply with applicable environmental laws, including the Alberta Environmental Protection and
Enhancement Act, the Environmental Management and Protection Act
(Saskatchewan), the Environmental Assessment Act (British
Columbia) and similar legislation or requirements in other jurisdictions in
which it operates.  Enerplus anticipates
that this compliance may result in increased expenditures of both a capital and
expense nature in order to comply with increasingly stringent laws relating to
the protection of the environment.  33 
   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 same
business.  Prospective investors should
carefully consider the following risk factors, together with other information
contained in this Renewal Annual Information Form and the information
incorporated by reference, before investing in the Trust Units.  Risks
Related to Enerplus Business  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
foregoes 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 or if hedging policies and procedures
are not followed.  34 
   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.  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.  35 
   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 senior
unsecured notes issued by EnerMark.  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 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 reserve 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
Renewal 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;  36 
   success
of future exploitation activities;  marketability
of production;  effects
of government regulation; and  other
government levies that may be imposed over the producing life of reserves.  Reserve estimates are based on the relevant factors, assumptions and
prices on the date the evaluations were prepared.  Many of these factors are subject to change and are beyond
Enerplus control.  If these factors,
assumptions and prices prove to be inaccurate, Enerplus actual reserves could
vary materially from its reserve estimates.  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 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.  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.  37 
   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.  Enerplus indebtedness
many 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 swapped 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.  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,  38 
   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.  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.  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.  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  39 
   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.  Enerplus conducts title reviews in accordance with industry practice
prior to any purchase of resource assets. However, 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.  Tax authorities having jurisdiction over
Enerplus or the unitholders may disagree with how Enerplus calculates its
income for tax purposes or could change administrative practices to Enerplus
detriment or the detriment of its unitholders.  There would be material
adverse tax consequences if the Fund lost its status as a mutual fund trust
under Canadian tax laws.  Enerplus intends that the Fund will continue to qualify as a mutual
fund trust for purposes of the Tax Act. 
The Fund may not, however, always be able to satisfy any future
requirements for the maintenance of mutual fund trust status.  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.  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,  40 
   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.  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 operation of the
Fund is entirely independent from the unitholders, and 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.  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.  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  41 
   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.  The redemption rights of
unitholders is limited.  Unitholders have a limited right to require the Fund to repurchase
Trust Units, which is referred to as a redemption right.  See Description of the Trust Units and the
Trust Indenture - Redemption Right.  It
is anticipated that the redemption right will not be the primary mechanism for
unitholders to liquidate their investment. 
The Funds ability to pay cash in connection with a redemption is
subject to limitations.  Any securities
which may be distributed in specie to unitholders in connection with a
redemption may not be listed on any stock exchange and a market may not develop
for such securities.  In addition, there
may be resale restrictions imposed by law upon the recipients of the securities
pursuant to the redemption right.  Risks
Particular to United States Unitholders  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 2003 taxable year and in subsequent taxable
years.  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.  The ability of United
States 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 outside the United States.  As a
result, it may be difficult for investors in the United States to effect
service of process within the United States upon such directors, officers and
representatives of experts who are not residents of the United States or to
enforce against them judgments of United States courts based upon civil
liability under the United States federal securities laws or the securities
laws of any state within the United States. 
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.  42 
   SELECTED
CONSOLIDATED FINANCIAL INFORMATION  The following tables set forth selected consolidated financial information
of Enerplus for the past three years.  Three Year Detailed Statistical Review  Year Ended December 31,2002
  
  2001
  
  2000(in thousands, except per Trust Unit amounts)FinancialGross oil and gas sales
  
  $
  621,450
  
  $
  639,397
  
  $
  343,182Funds flow from operations
  
  289,852
  
  340,246
  
  176,366Per Trust Unit
  
  4.03
  
  6.20
  
  6.57Net income
  
  115,876
  
  180,269
  
  82,150Per Trust Unit  Basic
  
  1.61
  
  3.28
  
  3.06Per Trust Unit  Diluted
  
  1.61
  
  3.28
  
  3.05Capital expenditures (net)
  
  203,639
  
  152,216
  
  65,844Total assets
  
  2,471,631
  
  2,284,253
  
  1,567,952Long term debt
  
  361,729
  
  412,589
  
  275,944Cash available
  for distributionFunds flow from operations
  
  289,852
  
  340,246
  
  176,366Site restoration and abandonment costs incurred
  
  
  
  2,628
  
  1,471Cash withheld for debt reduction
  
  (46,344
  )
  (48,850
  )
  (11,746
  )Enerplus Resources Fund (pre-Merger) cash flows
  
  
  
  16,870
  
  Accruals
  
  3,279
  
  5,560
  
  Pursuit Resources Corp. operating cash flows net of
  cash withheld for debt reduction
  
  
  
  
  
  2,090Cash available for distribution
  
  $
  246,787
  
  $
  316,454
  
  $
  168,181Per Trust Unit
  
  $
  3.32
  
  $
  5.67
  
  $
  5.49  The above financial data has been taken from the audited consolidated
financial statements of Enerplus for the years ended December 31, 2002, 2001
and 2000.  The audited consolidated
financial statements have been prepared in accordance with Canadian generally
accepted accounting principles.  See
Note 1 to Enerplus audited annual consolidated financial statements of the
year ended December 31, 2002 for a description of the significant accounting
policies of Enerplus.  Cash Distributions to Unitholders  Reference is made to the information under the heading Distributions
to Unitholders in this Renewal Annual Information Form.  MANAGEMENTS DISCUSSION AND ANALYSIS  Managements discussion and analysis of financial results for the year
ended December 31, 2002, as contained on pages 39 to 56 of the Funds Annual
Report for the year ended December 31, 2002, is incorporated by reference in
this Renewal Annual Information Form.  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.  43 
   DIRECTORS AND OFFICERS Directors of EnerMark  The directors of EnerMark are nominated by the unitholders of the Fund
at each annual meeting of unitholders. 
Prior to the Internalization Transaction (but including the nomination
of directors of EnerMark at the 2003 annual meeting of Unitholders), EGEM was
entitled to nominate three of the directors of EnerMark pursuant to the
Management Agreement at the Governance Agreement.  All directors, including the Nominees of EGEM, 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 and year of appointment as a director of
EnerMark for each director of EnerMark are set forth below:  Name and Municipality
  of Residence
  
  Director
  Since
  
  Principal
  Occupation for Past Five Years(9)André
  Bineau (2)
  Montréal, Québec
  
  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(4)(5)Ottawa, Ontario
  
  June 2001
  
  Secretary/Manager, City of Ottawa Superannuation
  Fund (a municipal pension plan).Gordon
  J. Kerr (6)(9)Calgary,
  Alberta
  
  May 2001
  
  President and Chief
  Executive Officer of Enerplus since May 2001 (and Chief Financial Officer of
  Enerplus until December 2001). 
  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
  
  July 2000
  
  President
  of Charles Avenue Capital Corp. (a private merchant banking company) since
  April, 2000. Chairman of the Board of Pursuit Resources Corp. (an oil and
  natural gas exploration and production company).Robert Normand (2)(4)(5)Rosemere, Québec
  
  June 2001
  
  Businessman.Eric
  P. Tremblay (3)(6)(9)Calgary,
  Alberta
  
  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 (3)Calgary,
  Alberta
  
  April 2003
  
  Businessman
  since October 1999.  Prior thereto, President
  and Chief Executive Officer of Rigel Energy Corporation.Harry
  B. Wheeler(2)(3)
  Calgary, Alberta
  
  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(6)(8)Houston,
  Texas
  
  January 2001
  
  Managing
  Director of EnCap Investments L.L.C. (a wholly owned subsidiary of El Paso
  Corporation, which provides private equity financing to the oil and gas
  industry).  
 Notes: (1)Chairman of the Board of
Directors. (2)The Audit and Risk
Management Committee is comprised of Robert Normand as Chairman, André Bineau
and Harry B. Wheeler. (3)The Environment, Safety
and Reserves Committee is comprised of Harry B. Wheeler as Chairman, Donald T.
West and Eric P. Tremblay. (4)The Corporate Governance
and Human Resources Committee is comprised of Douglas R. Martin as Chairman,
Robert Normand and Derek J. M. Fortune.  44 
   (5)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. (6)Nominee of EGEM pursuant
to the Management Agreement and the Governance Agreement (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 Internalization Transaction 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 the 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 and principal
occupation for the past five years for each officer of EnerMark are set out
below:  Name
  and
  Municipality of Residence
  
  Office
  
  Principal
  Occupation for Past Five Years(1)Gordon J. Kerr
  Calgary, Alberta
  
  President & Chief
  Executive Officer
  
  President and Chief
  Executive Officer of Enerplus since May 2001 (and Chief Financial Officer of
  Enerplus until December 2001).  Prior
  thereto, Executive Vice President and Chief Financial Officer of Enerplus
  since January 2001.  Prior thereto,
  Senior Vice President, Financial Services of Enerplus since September
  2000.  Prior thereto, Vice President,
  Finance and Chief Financial Officer of Enerplus since 1998.Heather J. Culbert
  Calgary, Alberta
  
  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
  
  Senior Vice President
  & 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 wholly owned subsidiary of El
  Paso Corporation which provides private equity financing to the oil and gas
  industry) since 1997.Eric P. Tremblay
  Calgary, Alberta
  
  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
  
  Senior Vice President
  & 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 since June 1998.Jo-Anne M. Caza
  Calgary, Alberta
  
  Vice President,
  Investor Relations
  
  Vice President of Investor
  Relations of Enerplus since September 2000. Prior thereto, Manager, Investor
  Relations of Enerplus since 1998.  45 
   Name
  and
  Municipality of Residence
  
  Office
  
  Principal
  Occupation for Past Five Years(1)Daryl W. Cook
  Calgary, Alberta
  
  Vice President,
  Operations
  
  Vice President, Operations
  of Enerplus since 1997.Ian C. Dundas
  Calgary, Alberta
  
  Vice President &
  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
  
  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
  
  General Counsel &
  Corporate Secretary
  
  General Counsel &
  Corporate Secretary of Enerplus since December 2002.  Prior thereto, Consultant, Offshore &
  International Operations, with EnCana Corporation since 2002.  Prior thereto, Vice President, General
  Counsel & Governmental Affairs with Conoco Canada Limited since
  2000.  Prior thereto, Alberta Counsel
  with Westcoast Energy Inc. since 1998.Daniel M. StevensCalgary, Alberta
  
  Vice President,
  Development Services
  
  Vice President, Development
  Services of Enerplus since February 2003. 
  Prior thereto, Manager, Drilling and Completions of Enerplus since
  1996.Wayne G. Ford
  Calgary, Alberta
  
  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
  
  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
  
  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 Internalization Transaction 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 the 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.  The directors and officers named above beneficially own, directly or
indirectly, an aggregate of 415,326 Trust Units, representing approximately
0.5% of the Trust Units outstanding on May 1, 2003.  Certain of the directors and officers named above may be directors or
officers of issuers which are in competition to 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.  46 
   ADDITIONAL INFORMATION  Enerplus will provide to any person, upon request to the Corporate
Secretary of Enerplus:  (a)when the securities of the Fund are in the
course of a distribution under a preliminary short form prospectus or a short
form prospectus:  (i)one copy of this Renewal Annual
Information Form, together with one copy of any document, or the pertinent
pages of any document, incorporated by reference in this Renewal Annual
Information Form;  (ii)one copy of the Funds comparative
financial statements for its most recently completed financial year for which
financial statements have been filed together with the accompanying report of
the auditors and one copy of the most recent interim financial statements of
the Fund that have been filed, if any, for any period after the end of its most
recently completed financial year;  (iii)one copy of the information circular
of the Fund in respect of its most recent annual meeting of unitholders that
involved the election of directors of EnerMark or one copy of any annual filing
prepared instead of that information circular, as appropriate; and  (iv)one copy of any other documents that
are incorporated by reference into the preliminary short form prospectus or
short form prospectus and are not required to be provided under (i) to (iii)
above; or  (b)at any other time, one copy of any
other documents referred to in clauses (a)(i), (ii) and (iii) above, provided
that Enerplus may require the payment of a reasonable charge if the request is
made by a person who is not a securityholder of the Fund.  Additional information regarding directors and certain officers
remuneration and indebtedness, principal holders of Trust Units, options and
rights to purchase Trust Units and interests of insiders in material transactions
is contained in the Funds information circular for its most recent annual
meeting of unitholders that involved the election of directors of EnerMark.
Additional information is provided in Enerplus comparative consolidated
financial statements for the year ended December 31, 2002.  47 
    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  48