Document:

<PAGE>

                                                                    EXHIBIT 4.3

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                         [ENERPLUS RESOURCES FUND LOGO]

                         RENEWAL ANNUAL INFORMATION FORM

                      FOR THE YEAR ENDED DECEMBER 31, 2001

                                 APRIL 10, 2002

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<PAGE>

                                TABLE OF CONTENTS
<TABLE>

<S>                                                                                               <C>
GLOSSARY OF TERMS..................................................................................ii

ABBREVIATIONS......................................................................................iv

CONVERSION.........................................................................................iv

NOTE TO READER......................................................................................1

STRUCTURE OF ENERPLUS RESOURCES FUND................................................................1

GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND......................................................3

OPERATIONAL INFORMATION.............................................................................5

         Description of Principal Properties........................................................5

         Summary of Production Locations...........................................................10

         Location of Facilities....................................................................10

         Drilling Activities and Results...........................................................12

         Oil and Natural Gas Wells and Lease Holdings..............................................13

         Reserves Reconciliation...................................................................13

         Historical Production Revenues............................................................13

         Quarterly Production History..............................................................14

         Quarterly Netback History.................................................................14

         Quarterly Capital Expenditures............................................................15

         Exploration and Development...............................................................16

         Marketing Arrangements....................................................................16

         Impact of Environmental Protection Requirements...........................................17

OIL AND NATURAL GAS RESERVES.......................................................................17

INFORMATION RESPECTING ENERPLUS RESOURCES FUND.....................................................21

         Operations of Enerplus....................................................................21

         Description of the Trust Units and the Trust Indenture....................................23

         Royalty Agreements........................................................................27

         Governance of Enerplus and the Management Agreement.......................................28

         Governance Agreement......................................................................31

         Unitholder Rights Plan....................................................................32

DISTRIBUTIONS TO UNITHOLDERS.......................................................................32

INDUSTRY CONDITIONS................................................................................33

RISK FACTORS.......................................................................................35

SELECTED CONSOLIDATED FINANCIAL INFORMATION........................................................40

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND RESULTS OF OPERATIONS.............40

MARKET FOR SECURITIES..............................................................................41

DIRECTORS AND OFFICERS.............................................................................41

ADDITIONAL INFORMATION.............................................................................45

APPENDIX "A" - UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS..............................A-1
</TABLE>

                                      -i-
<PAGE>

                                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.

"ECONOMIC LIFE" means, with respect to an oil and gas property, the time
remaining before production of petroleum substances from the property is
forecast to be uneconomic;

"EGEM" means Enerplus Global Energy Management Company, a private company, which
acts as 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;

"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;

"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;

"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";

"RESERVE LIFE INDEX" or "RLI" is an index reflecting the theoretical production
life of a property if the remaining reserves were to be produced out at current
production rates. The index is calculated by dividing the reserves in the
selected reserve category at a certain date by the estimated production for the
following 12 month period;

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

"SPROULE REPORT" means the independent engineering evaluations of Enerplus' oil,
NGLs and natural gas interests prepared by Sproule dated March 4, 2002 and
effective January 1, 2002, utilizing commodity price forecasts of Sproule dated
January 1, 2002;

"TERMINATION COSTS" means all costs, expenses or obligations which are incurred
by EGEM or its affiliates within 90 days following the effective date of
termination of the Management Agreement (the "TERMINATION DATE") as a direct or
indirect result of:

(i)      any termination, retirement or severance of any officers, employees or
         consultants of EGEM or its affiliates to the extent that the provision
         of services by any such officer, employee or consultant is allocable
         (based on the prior calendar year) to the provision of the services of
         EGEM under the Management Agreement prior to its termination
         ("TERMINATED PERSONNEL");

                                      -ii-

<PAGE>

(ii)     the termination or cancellation of any agreement, contract, lease or
         other commitment applicable to the services provided under this
         Agreement that pre-existed the Management Agreement (a "TERMINATED
         PRE-EXISTING CONTRACT"); and

(iii)    the termination or cancellation of any agreement, contract, lease or
         other commitment applicable to the services provided under this
         Agreement that was entered into on or after the date of the Management
         Agreement (a "TERMINATED POST-MERGER CONTRACT"),

provided, however, that: (A) no cost, expense or obligation shall be included as
a "Termination Cost" if it is applicable to a Terminated Post-Merger Contract:
(i) having a term extending more than 36 months after the Termination Date of
the Management Agreement; or (ii) involving aggregate costs, expenses or
obligations of $2,000,000 or more, unless such Terminated Post-Merger Contract
was approved by the board of directors of EnerMark at any time prior to the
Termination Date; and (B) the costs, expenses or obligations applicable to
termination, retirement or severance of Terminated Personnel shall not exceed,
in the aggregate, the sum of: (i) all amounts payable pursuant to any written
agreement with Terminated Personnel which was approved by the board of directors
of EnerMark at any time prior to the Termination Date (an "APPROVED EMPLOYMENT
AGREEMENT"); and (ii) the aggregate of the annual remuneration (including
salary, bonuses, benefits, any rights or entitlements to options or incentives
under corporate plans or other employment compensation) of all Terminated
Personnel, other than those whose payments are made pursuant to an Approved
Employment Agreement, for the last fiscal year of the Fund ending prior to the
Termination Date, provided, however that there shall be no duplication of any
amounts under terms (B)(i) and (B)(ii) above;

"TERMINATION FEES" means an amount equal to the annualized average of the base
management fee paid to EGEM in each of the trailing eight quarters ending
immediately prior to the quarter in which notice of termination of the
Management Agreement is provided to EGEM;

"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.

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

                                     -iii-
<PAGE>

                                  ABBREVIATIONS
<Table>
<Caption>
OIL AND NATURAL GAS LIQUIDS                NATURAL GAS
---------------------------                -----------
<S>                                        <C>

BBLS - barrels                             GJ - gigajoules

MBBLS - thousand barrels                   GJ/D - gigajoules per day

BOPD - barrels of oil per day              MCF - thousand cubic feet

BBLS/D - barrels per day                   MMCF - million cubic feet

MMBBLS - million barrels                   BCF - billion cubic feet

NGLS - natural gas liquids                 MCF/D - thousand cubic feet per day

                                           MMCF/D - million cubic feet per day

                                           MMBTU - million British Thermal Units
</Table>

OTHER

AECO  means Alberta Energy Company interconnect with the NOVA System.

BOE   means barrel of oil equivalent, using the conversion factor of 6 Mcf of
      natural gas being equivalent to one barrel of oil. The conversation
      factor used to convert natural gas to oil equivalent is not necessarily
      based upon either energy or price equivalents at this time.

BOE/D means BOE per day.

MBOE  means thousand barrel of oil equivalent.

W.I.  means working interest

WTI   West Texas Intermediate at Cushing, Oklahoma, the benchmark crude oil for
      pricing purposes.

                                   CONVERSION

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

<TABLE>
<CAPTION>
      TO CONVERT FROM                    TO                             MULTIPLY BY
      ---------------                    --                             -----------
      <S>                                <C>                            <C>
      Mcf                                cubic metres                   28.174
      cubic metres                       cubic feet                     35.494
      Bbls                               cubic metres                    0.159
      cubic metres                       Bbls                            6.293
      Feet                               Metres                          0.305
      metres                             Feet                            3.281
      Miles                              Kilometres                      1.609
      Kilometres                         Miles                           0.621
      Acres                              Hectares                        0.405
      Hectares                           Acres                           2.471
      GJ                                 MMBTU                           0.950
</TABLE>

                                      -iv-
<PAGE>

                             ENERPLUS RESOURCES FUND

                         RENEWAL ANNUAL INFORMATION FORM
                      FOR THE YEAR ENDED DECEMBER 31, 2001

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                                 NOTE TO READER

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, OPERATIONAL AND
OIL AND NATURAL GAS RESERVE INFORMATION CONTAINED IN THIS RENEWAL ANNUAL
INFORMATION FORM, TOGETHER WITH THE MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS INCORPORATED BY REFERENCE IN THIS
RENEWAL ANNUAL INFORMATION FORM, IS BASED ON THE HISTORICAL FINANCIAL AND
OPERATIONAL RESULTS OF ENERMARK INCOME FUND, AND 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. THE PRODUCTION AND OPERATIONAL INFORMATION RELATING
TO THE PRE-MERGER ENERPLUS RESOURCES FUND HAS BEEN INCLUDED IN THE INFORMATION
FOR THE CURRENT ENERPLUS RESOURCES FUND SINCE JUNE 21, 2001, THE EFFECTIVE DATE
OF THE MERGER, AND THE RESERVE INFORMATION AS OF JANUARY 1, 2002 INCLUDES ALL
RESERVES OF ENERPLUS AS OF THAT DATE, INCLUDING THOSE ACQUIRED PURSUANT TO THE
MERGER.
--------------------------------------------------------------------------------

                      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 and currently governed by the Trust Indenture.
The Fund's assets currently consist of all of the issued and outstanding shares
of EnerMark (which owns all of the issued and outstanding shares of 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 1900, 700 -
9th Avenue S.W., Calgary, Alberta T2P 3V4 until June 1, 2002, when it will be
relocated to 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 is managed by EGEM pursuant
to the Management Agreement.

The Fund's primary focus is to maintain and enhance cash distributions to its
unitholders through the development of EnerMark's and ERC's existing crude oil
and natural gas properties, acquisition of new producing properties and
monetization, by the way of sale or farm out, of EnerMark's and ERC's
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. EnerMark and ERC are managed by EGEM pursuant to the
Management Agreement. Pursuant to the Governance Agreement, EGEM is entitled to
nominate three members to the board of directors of EnerMark (the entity
responsible for the governance of Enerplus), with the balance, which must
constitute a majority of the directors of EnerMark, to be nominated pursuant to
a vote by the unitholders of the Fund.

                                      -1-
<PAGE>

EnerMark and ERC 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.

ENERPLUS GLOBAL ENERGY MANAGEMENT COMPANY

EGEM is a corporation organized under the COMPANIES ACT (Nova Scotia) and is an
indirect wholly owned subsidiary of El Paso Corporation of Houston, Texas. EGEM
manages the Fund and its subsidiaries pursuant to the Management Agreement. The
board of directors of EnerMark, as the body which oversees the business and
affairs of Enerplus, has retained EGEM to provide comprehensive management
services, administer and regulate the day-to-day operations and make executive
decisions in respect of Enerplus which conform to general policies and
principles established by the board of directors of EnerMark. For these
services, EGEM receives a management fee, incentive fees based on the
performance of Enerplus and reimbursement of its general and administrative
expenses. See "Information Respecting Enerplus Resources Fund - Governance of
Enerplus and the Management Agreement".

ORGANIZATION CHART

The structure of Enerplus and the flows of cash from EnerMark and ERC to the
Fund and from the Fund to its unitholders are set forth below:

Unitholders own all of the outstanding trust units of Enerplus Resources
Fund. Enerplus Resources Fund owns all of the shares of EnerMark Inc., which
owns all of the shares of Enerplus Resources Corporation. Both EnerMark Inc.
and Enerplus Resources Corporation own oil and gas assets. EnerMark Inc. has
issued an unsecured promissory note to Enerplus Resources Fund and pays a 95%
royalty on its oil and gas production income to Enerplus Resources Fund.
Enerplus Resources Corporation pays a 99% royalty on its oil and gas
production income to Enerplus Resources Fund. Enerplus Global Energy
Management Company manages each of Enerplus Resources Fund, EnerMark Inc. and
Enerplus Resources Corporation pursuant to a management agreement.

                                      -2-
<PAGE>

                 GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND

HISTORICAL OVERVIEW

Enerplus was formed in 1986 and was the first issuer in Canada to offer trust
units to the public and to list its trust units on a stock exchange. Enerplus
was historically one of a group of royalty trusts, income funds and other
entities managed by the Enerplus Group of Companies, and in recent years has
grown significantly as a result of consolidation of many of those entities, as
discussed below.

MERGER WITH WESTROCK ENERGY INCOME FUND I AND WESTROCK ENERGY INCOME FUND II

On June 8, 2000, unitholders of each of Enerplus, Westrock Energy Income Fund I
("Westrock I") and Westrock Energy Income Fund II ("Westrock II") approved the
merger of those issuers, which was completed the same day. Enerplus issued an
aggregate of approximately 8,911,667 Trust Units (after giving effect to one for
six consolidation of the Trust Units that occurred concurrently with the merger)
to former unitholders of Westrock I and Westrock II in connection with the
merger. Following this transaction, a total of approximately 15,473,000 Trust
Units were issued and outstanding. Enerplus, Westrock I and Westrock II were
managed by affiliated management companies which were part of the Enerplus Group
of Companies (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 an independent special committee of the board of directors
responsible for each respective 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 sale of the
management companies responsible for the management of Enerplus' various public
and private funds, including the manager of Enerplus. El Paso has operations in
natural gas transmission, merchant energy services, power generation,
international project development, natural gas gathering and oil and natural gas
production.

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.

ACQUISITION OF EPRC III

On December 19, 2000, Enerplus completed the acquisition of all of the
outstanding shares of Enerplus Pension Resource Corporation ("EPRC III"), a
private Canadian pension resource corporation that owned producing oil and
natural gas properties in western Canada, for consideration of $90 million plus
the assumption of bank debt and working capital balances. The effective date of
the transaction was November 30, 2000. EPRC III was managed by a predecessor of
EGEM. The transaction was negotiated on an arm's length basis on behalf of
Enerplus by an independent special committee of the board of directors of ERC
(the entity responsible for the governance of Enerplus at that time) with the
independent directors and shareholders of EPRC III. The acquisition was funded
through a combination of cash from existing credit facilities and the assumption
of debt, which together represented 75% of the purchase price, and the issuance
of 1,145,375 Trust Units which represented the remaining 25% of the purchase
price. EPRC III was amalgamated with ERC on December 29, 2000 and continued as
"Enerplus Resources Corporation".

                                      -3-
<PAGE>

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, and each outstanding warrant to
purchase an EnerMark Income Fund Unit was substituted with 0.173 of a warrant to
purchase a Trust Unit of Enerplus (an "Enerplus Warrant"). Each whole Enerplus
Warrant was exercisable into a Trust Unit at an exercise price of $26.53 on or
before December 17, 2001. A total of approximately 43,525,961 Trust Units of the
Fund and 2,507,330 Enerplus Warrants were issued to former holders of EnerMark
Income Fund Units and warrants, respectively. Immediately following the Merger,
there were approximately 64,388,336 Trust Units and 2,507,330 Enerplus Warrants
issued and outstanding.

Enerplus and EnerMark were managed by affiliated management companies which were
part of the Enerplus Group of Companies (and each of which was a subsidiary of
EGEM). 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 an independent special committee of the board
responsible for each respective entity.

EnerMark Income Fund was created on April 3, 1996 as a result of a corporate
reorganization of Mark Resources Inc. by way of a plan of arrangement. From 1997
through 2000, EnerMark Income Fund made several corporate and asset
acquisitions, including the acquisitions of Quest Oil & Gas Inc. in 1997,
Derrick Energy Corporation in 1999 and Western Star Exploration Ltd., Pursuit
Resources Corp., EBOC Energy Ltd. and Cabre Exploration Ltd., in addition to an
asset acquisition in the Hanna, Alberta area, in 2000. Additional details
regarding the corporate acquisitions made in 1999 and 2000 are contained in Note
7 of Enerplus' audited annual consolidated financial statements for the year
ended December 31, 2001.

ATTACHED AS APPENDIX "A" TO THIS RENEWAL ANNUAL INFORMATION FORM ARE CERTAIN
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF ENERPLUS FOR THE YEAR
ENDED DECEMBER 31, 2001 WHICH GIVE EFFECT TO THE MERGER AS IF IT HAD OCCURRED ON
JANUARY 1, 2001.

PROPERTY ACQUISITIONS AND DISPOSITIONS IN 2001

In 2001, Enerplus made several property acquisitions for an aggregate cost of
approximately $77 million. The most significant of these acquisitions were made
in the Kaybob, Ferrier, Joarcam, Medicine Hat and Hanna Garden areas of Alberta
and the Gleaneath area of Saskatchewan. Production from the acquired properties,
at the time of their respective acquisitions, was approximately 1,113 Bbls/d of
crude oil and NGLs and 10.5 MMcf/d of natural gas.

Additionally, Enerplus undertook a property rationalization program in 2001
which was designed to enable it to focus its activities on high yield
properties. Under the program, over 40 non-core properties were sold. Proceeds
from the sales totalled approximately $68 million, and daily production from
these properties, at the time of their respective sales, was approximately 1,266
Bbls/d of crude oil and NGLs and 4.8 MMcf/d of natural gas.

RECENT DEVELOPMENTS SINCE FISCAL YEAR-END

COMMODITY PRICE RISK MANAGEMENT PROGRAM

On January 8, 2002, Enerplus entered into a three-way financial option structure
for 1,500 Bbls/d of crude oil from April 2002 to December 2003. Under the terms
of this structure, Enerplus purchased a WTI put at US$19.50/Bbl, sold a WTI call
at US$27.00/Bbl and sold a WTI put at $US17.00/Bbl. On this same date, Enerplus
also entered into a three-way option structure on 9,480 Mcf/d of natural gas for
the period from April 2002 to October 2002, selling an AECO call at $4.22/Mcf,
purchasing an AECO put at $3.29/Mcf and selling an AECO put at $2.37/Mcf,

                                      -4-
<PAGE>

and additionally, Enerplus sold an AECO call at $6.33/Mcf on 9,480 Mcf/d of
natural gas for the period from November 2002 to March 2003.

On March 6, 2002, Enerplus entered into two additional three-way financial
option structures. One structure comprised 1,500 Bbls/d of crude oil from April
2002 to December 2003 wherein Enerplus purchased a WTI put at US$20.10/Bbl, sold
a WTI call at US$28.00/Bbl and sold a WTI put at US$17.00/Bbl. The other
structure comprised 1,500/Bbls/d of crude for all of calendar 2003 wherein
Enerplus purchased a WTI put at US$20.15/Bbl, sold a WTI call at US$28.00/Bbl
and sold a WTI put at US$17.00/Bbl.

                             OPERATIONAL INFORMATION

As mentioned in the "Note to Reader" on page 1, all historical operational and
reserve information 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
been included in the information for the current Enerplus Resources Fund since
June 21, 2001, the effective date of the Merger, and the reserve information as
of January 1, 2002 includes all reserves of Enerplus as of that date, including
those acquired pursuant to the Merger.

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 interest in the province of Manitoba). Production volumes from Enerplus'
properties are approximately 45% crude oil and NGLs and 55% natural gas on a BOE
basis. During the year ended December 31, 2001, Enerplus' oil and natural gas
property interests yielded average production of 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, compared to 12,089 Bbls/d of crude oil, 2,111 Bbls/d of NGLs and 101.5
MMcf/d of natural gas for a total of 31,112 BOE/d during 2000. 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, 2002 the
oil and natural gas property interests held by Enerplus are estimated to contain
Established Reserves of 132.1 MMbbls of crude oil and NGLs and 1,081.5 Bcf of
natural gas. See "Oil and Natural Gas Reserves".

The following paragraphs discuss the principal producing properties of Enerplus
including, where applicable, the additional properties or working interests
acquired through the Merger with EnerMark Income Fund effective June 21, 2001.
All production information represents the net working interest of Enerplus in
such property before deduction of royalty interests owned by others, and
production figures for the year ended December 31, 2001 only include, where
applicable, net average production attributable to the acquired pre-Merger
Enerplus Resources Fund interests for the period from June 21, 2001 to December
31, 2001. All references to reserve volumes contained in each property are based
upon the estimated volumes contained within the Sproule Report applicable to
Enerplus' gross working interest in the property.

JOARCAM, ALBERTA

Enerplus has varying working interests averaging 80% in the Joarcam area of
central Alberta located 300 kilometres northeast of Calgary, Alberta. The
Joarcam area, which Enerplus operates, produces crude oil, solution gas and gas
cap natural gas from the Viking formation as well as non-associated natural gas
from the Mannville formations. Production from this area in December 2001 was
2,177 Bbls/d of crude oil, 149 Bbls/d of NGLs and 8.0 MMcf/d of natural gas for
a total of 3,640 BOE/d. All crude oil and gas produced from this property is
processed at Enerplus operated facilities. Plans for 2002 include the drilling
of up to 18 infill Viking crude oil wells, 6 non-associated gas wells, and
on-going re-completions, tie-ins and facility optimizations. As at January 1,
2002, Enerplus' property interests in this area contained 12,337 MBOE of
Established Reserves. Production from this property is sold at the prevailing
spot price under short-term contracts.

                                      -5-
<PAGE>

MEDICINE HAT REGION

The Medicine Hat region of southern Alberta is primarily a natural gas producing
region which Enerplus operates and in which Enerplus has an average working
interest of 95%. In 2001, production from this region averaged 17.0 MMcf/d of
natural gas net to Enerplus from four core properties. A significant portion of
Enerplus' property interests in this region was acquired from the pre-Merger
Enerplus Resources Fund. This area was one of Enerplus' most active areas with a
total of 156 (135 net) natural gas wells drilled during the year. The majority
of the wells were drilled and brought on-stream in the fourth quarter, and as a
result natural gas sales averaged 32.9 MMcf/d in December 2001. As at January 1,
2002, the interests of Enerplus in the Medicine Hat region contained 46,354 MBOE
of Established Reserves. Further information regarding each of the four
properties in this area is contained below.

BANTRY, ALBERTA

Enerplus owns an average 95% working interest in the Bantry Field located
approximately 200 kilometres southeast of Calgary near Brooks, Alberta. Natural
gas from this property, which Enerplus operates, is primarily produced from the
Milk River and Medicine Hat formations. During the second and fourth quarters of
2001, Enerplus installed additional compression and drilled an additional 98
shallow natural gas infill wells. As a result, December 2001 production averaged
12.1 MMcf/d and 38 drilled wells were brought on-stream in the first quarter of
2002. Plans for 2002 include additional drilling of up to 25 wells to further
develop the pool on an 80 acre spacing and to keep the compression facilities
running at capacity. As at January 1, 2002, Enerplus' interests in the Bantry
property contained 16,267 MBOE of Established Reserves. A total of 3.8 MMcf/d of
production from this property is sold under a fixed price arrangement at
$2.64/Mcf which expires on October 31, 2002. The remainder of production from
this property is sold at the prevailing spot price under short-term contracts.

FOX VALLEY, SASKATCHEWAN

Enerplus has a 96.8% working interest in the Fox Valley property located
approximately 400 kilometres southeast of Calgary in the shallow natural gas
producing region of southwestern Saskatchewan. The natural gas from this
property, which Enerplus operates, is produced from the Milk River formation. In
December 2001, this property averaged production of approximately 4.2 MMcf/d of
natural gas from 152 (147 net) natural gas wells. Plans are to drill up to 25
infill natural gas wells in 2002. As at January 1, 2002, Enerplus' Fox Valley
property interests contained 4,349 MBOE of Established Reserves. A total of 2.8
MMcf/d of natural gas produced from this property has been sold under a fixed
price arrangement at $2.64/Mcf which expires on October 31, 2003. The remainder
of production from this property is sold at the prevailing spot price under
short-term contracts.

MEDICINE HAT, ALBERTA

Enerplus owns various working interests ranging from 20% to 100% in this
Medicine Hat shallow natural gas field located 300 kilometres southeast of
Calgary. The natural gas from this property, which Enerplus operates, is
produced from the Medicine Hat and Milk River formations. As a result of
successful restimulation and infill drilling programs in the third and fourth
quarters of 2001, this property averaged production of approximately 9.9 MMcf/d
of natural gas at the end of 2001. In 2002, Enerplus' plans for this property
include installing additional compression, restimulating existing wells and
reducing the well spacing by infill drilling 75 additional shallow natural gas
wells. As at January 1, 2002, Enerplus' property interest in the Medicine Hat
property contained 15,239 MBOE of Established Reserves. A significant portion of
these reserves are dedicated under long term contracts to major netback priced
pool aggregators. The remainder of the natural gas production from this area is
sold at the prevailing spot price under short-term contracts.

VERGER, ALBERTA

Enerplus owns various working interests in the Verger area located approximately
100 kilometres southeast of Calgary. Enerplus operates the majority of the
production and owns an average 80% working interest in 175 natural gas wells.
Enerplus' production from this property in December 2001 averaged 6.5 MMcf/d,
primarily from the Milk

                                      -6-
<PAGE>

River and Medicine Hat formations. An additional 20 operated wells were brought
on-stream in the first quarter of 2002 and plans are to drill 29 shallow gas
infill wells later in 2002. As at January 1, 2002, Enerplus' Verger property
interests contained 10,499 MBOE of Established Reserves. The production from
this property is sold at the prevailing spot price under short-term contracts.

DEEP BASIN, ALBERTA

Enerplus has an average working interest of 8% in the non-operated Deep Basin
property which encompasses the Elmworth, Karr, Wapiti, and South Wapiti
producing fields which are located approximately 500 kilometres northwest of
Calgary, Alberta. In 2001, this property produced 2,103 BOE/d comprised of 9.5
MMcf/d of natural gas and 519 Bbls/d of NGLs. Enerplus owns sufficient capacity
in compressor stations, natural gas gathering systems and natural gas processing
plants to process its production from the 320 wells in which it has a working
interest. As at January 1, 2002, Enerplus' property interest contained 8,201
MBOE of Established Reserves. Natural gas production from this property is
marketed under a long-term contract to a major netback priced pool operator.

PROGRESS, ALBERTA

Enerplus has a 100% working interest in the operated portion of the Progress
area located approximately 600 kilometres northwest of Calgary, Alberta, which
produces crude oil and solution gas from the Boundary Lake formation. Enerplus
also has a 27% working interest in the partner-operated Progress Halfway Gas
Unit which produces non-associated gas from the Halfway formation. In 2001,
production from this property averaged 784 Bbls/d of crude oil, 107 Bbls/d of
NGLs and 6.9 MMcf/d of natural gas for a total of 2,043 BOE/d. As at January 1,
2002, Enerplus' total property interests in this area contained 4,307 MBOE of
Established Reserves. Crude oil and NGLs production is marketed at the
prevailing market price under short-term contracts. Natural gas production is
sold under a variety of contracts including major netback priced pool
aggregators and short-term contracts at the prevailing spot price, and is
marketed in the U.S. midwest via Enerplus' natural gas pipeline commitments.

HANNA GARDEN PLAINS, ALBERTA

Enerplus has various working interests in the Hanna Garden Plains field and owns
an average 80% working interest in 258 wells. This property, which is operated
by Enerplus, is located approximately 200 kilometres northeast of Calgary,
Alberta. The primary producing zone is the Second White Specks, which averaged
production of 10.9 MMcf/d in 2001. In 2001, Enerplus drilled 92 Second White
Specks natural gas wells and expanded the two field compressor sites, and as a
result, production in December 2001 was 13.8 MMcf/d. Plans for the property in
2002 are to drill up to 75 additional natural gas wells, the majority of which
will complete development of the lands on 320-acre spacing. As at January 1,
2002, Enerplus' property interest in this area contained 29,118 MBOE of
Established Reserves. The natural gas produced from this area is marketed under
a variety of contracts including major net priced pool aggregators and
short-term contracts at the prevailing spot price.

BENJAMIN, ALBERTA

Enerplus has an average working interest of 20% in the 7 producing natural gas
wells in this area which is located in the foothills approximately 80 kilometres
northwest of Calgary, Alberta. These wells produce from the Turner Valley
formation. This property produced 10.0 MMcf/d of natural gas for the year 2001.
Several follow-up development drilling locations have been identified with the
first one drilled in mid-2001 in conjunction with Enerplus' participation in a
compression and pipeline project, which will ensure plant processing capacity
will be available for Enerplus' needs. The well commenced production in November
2001 and produced 3.9 MMcf/d of sales natural gas net to Enerplus through the
end of 2001. As at January 1, 2002, Enerplus' property interest contained 13,947
MBOE of Established Reserves. Production from this property is sold both to a
major netback priced pool aggregator and at the prevailing spot price under
short-term contracts.

                                      -7-
<PAGE>

GILTEDGE, ALBERTA

Enerplus has a 100% working interest in and operates the Giltedge field located
350 kilometres northeast of Calgary, Alberta. In December 2001, production
averaged 1,661 Bbls/d of crude oil and 643 Mcf/d of natural gas, for a total of
1,769 BOE/d, from this Lloydminster zone waterflood. A horizontal oil well and
four vertical oil wells are planned for this pool in 2002. As at January 1,
2002, Enerplus' property interests in this area contained 10,827 MBOE of
Established Reserves. Production from this property is sold at the prevailing
spot price under short-term contracts.

VALHALLA, ALBERTA

Enerplus has varying working interests averaging 80% in the Valhalla area
located approximately 500 kilometres northwest of Calgary, Alberta. The Valhalla
area, which Enerplus operates, produces crude oil and natural gas from the Doe
Creek, Bluesky, Boundary Lake and Halfway formations. During 2001, Enerplus'
production from this area averaged 1,453 BOE/d consisting of 377 Bbls/d of crude
oil, 5.9 MMcf/d of natural gas and 86 Bbls/d of NGLs. Crude oil and natural gas
is either processed at Enerplus owned and operated facilities or at non-operated
facilities. Plans for 2002 include additions to and optimization of existing
compression at the operated facilities. Enerplus also intends to drill several
infill Halfway crude oil wells in 2002 to optimize both crude oil and natural
gas recovery from the existing pool. As at January 1, 2002, Enerplus' property
interests in this area contained 5,293 MBOE of Established Reserves. Crude oil
and NGLs production is marketed at the prevailing market price under short-term
contracts. Natural gas production is sold under a variety of contracts including
major netback priced pool aggregators and short-term contracts at the prevailing
spot price, and is marketed in the U.S. midwest via Enerplus' natural gas
pipeline commitments.

PEMBINA FIVE-WAY / SOUTH BUCK LAKE, ALBERTA

Enerplus acquired from the pre-Merger Enerplus Resources Fund working interests
of up to 100% in certain lands in the Pembina Five-Way area and a 100% working
interest in the South Buck Lake Cardium Unit No. 1, located approximately 300
kilometres north of Calgary, with 304 (217 net) wells in this area. Enerplus
operates this area, and the crude oil produced from the Cardium zone in this
area is of high quality and is supported by long-life, low decline reserves. The
majority of the production is under secondary recovery schemes designed to
maximize the recoverable reserves. In December 2001, production averaged 2,215
Bbls/d of crude oil, 108 Bbls/d of NGLs and 1.4 MMcf/d of natural gas, for a
total of 2,550 BOE/d. As at January 1, 2002, this property contained 28,251 MBOE
of Established Reserves net to Enerplus. Crude oil produced from this area is
marketed under a 30 day evergreen contract with either an end use refinery or
intermediary. The natural gas produced from this property is marketed at the
prevailing spot price under short-term contracts.

BASHAW, ALBERTA

Enerplus has varying working interests ranging from 50% to 100% in the Bashaw
area located approximately 130 kilometres northeast of Calgary, Alberta. This
Enerplus-operated area produces natural gas primarily from the Belly River and
Mannville formations. In December 2001, production from this area averaged 6.8
MMcf/d of natural gas and 66 Bbls/d of NGLs for a total of 1,199 BOE/d. The
natural gas is compressed and processed through Enerplus owned and operated
infrastructure as well as third party gas processing plants. Plans for 2002
include field compression optimization and uphole gas re-completions. As at
January 1, 2002, Enerplus' property interests in this area contained 942 MBOE of
Established Reserves. Production from this property is sold at the prevailing
spot price under short-term contracts.

PINE CREEK, ALBERTA

Enerplus has both operated and non-operated production in working interests
ranging from 50% to 100% in the Pine Creek area located approximately 500
kilometres northwest of Calgary, Alberta. The Pine Creek area produces liquids
rich natural gas from the Bluesky, Gething and Ostracod formations. In December
2001, production averaged 5.8 MMcf/d of natural gas and 225 Bbls/d of NGLs for a
total of 1,192 BOE/d. The majority of production from this

                                      -8-
<PAGE>

area is compressed and processed through Enerplus-owned infrastructure with a
portion of the natural gas handled through third party gas plants. As at January
1, 2002, Enerplus' property interests in this area contained 9,955 MBOE of
Established Reserves. Production from this property is sold at the prevailing
spot price under short-term contracts.

KAYBOB, ALBERTA

Enerplus has both operated and non-operated production in working interests
ranging from 50% to 100% in the Kaybob area located approximately 300 kilometres
north of Calgary, Alberta. In June 2001, additional working interests in this
area were acquired for approximately $25 million. The Kaybob area produces
liquids rich natural gas from the Bluesky, Gething, Viking and Notikewin
formations. In 2001, production averaged 3.9 MMcf/d of natural gas and 419
Bbls/d of NGLs for a total of 1,066 BOE/d. As at January 1, 2002, Enerplus'
interests in this property contained 7,884 MBOE of Established Reserves. NGLs
production from this property is marketed at the prevailing market price under
short-term contracts. natural gas production is sold under a variety of
contracts including major netback priced pool aggregators and short-term
contracts at the prevailing spot price, and is marketed in the U.S. midwest via
Enerplus' natural gas pipeline commitments.

AUBURNDALE, ALBERTA

Enerplus has an average 80% working interest in and operates the Auburndale
field located 350 kilometres northeast of Calgary, Alberta. There are 21
producing crude oil wells and 4 producing natural gas wells on this property
that averaged production of 752 Bbls/d of crude oil and 800 Mcf/d of natural
gas, for a total of 885 BOE/d, in 2001. Plans for 2002 are to drill three infill
wells in the Sparky formation and complete the development of the pool on 20
acre spacing. As at January 1, 2002, Enerplus' property interests in this area
contained 1,161 MBOE of Established Reserves. Production from this property is
sold at the prevailing spot price under short-term contracts.

MEDICINE HAT GLAUCONITIC C POOL, ALBERTA

Enerplus has various working interests which average 71% in this large crude oil
pool which Enerplus operates and which is located approximately 350 kilometres
southeast of Calgary near Medicine Hat, Alberta. In 2001, a portion of this pool
was unitized and a waterflood scheme was implemented to enhance crude oil
recovery. Full-scale injection into the pool commenced in June, 2001. Additional
working interests in the pool were acquired in the fourth quarter of 2001.
Enerplus owns a 44% working interest in the unitized lands that encompass 5,040
acres. As a result of production improvements experienced due to the waterflood
and the additional working interest acquired, production averaged 800 Bbls/d of
crude oil and 1.0 MMcf/d of natural gas in December 2001 for a total of 967
BOE/d. As at January 1, 2002, this property contained 7,649 MBOE of Established
Reserves. Both crude oil and natural gas produced from this property are
marketed at the prevailing spot price under short-term contracts.

SYLVAN LAKE, ALBERTA

Enerplus acquired from the pre-Merger Enerplus Resources Fund both operated and
non-operated working interests in this area located approximately 130 kilometres
northwest of Calgary. Enerplus has an 85% working interest in and operates a
Pekisko crude oil pool with 18 gross (15.3 net) producing oil wells on 1,280
(1,088 net) acres. The Pekisko zone in this area has been under development by
the pre-Merger Enerplus Resources Fund since 1996 with 8 successful gross (7.2
net) oil wells drilled in the last three years. The production is treated at the
operated battery facilities located in this area. Enerplus also has a 19%
working interest in 32,640 acres in the non-operated Sylvan Lake Gas Unit No. 1
which consists of 20 gross (3.8 net) producing natural gas wells producing from
the Glauconitic, Basal Quartz, Ostracod, Jurassic, Elkton-Shunda and Pekisko
formations.

During the last six months of 2001, production from this area averaged 527
Bbls/d of crude oil, 3.2 MMcf/d of natural gas and 184 Bbls/d of NGLs for a
total of 1,250 BOE/d. As at January 1, 2002, Enerplus' total Sylvan Lake
property interests contained 4,927 MBOE of Established Reserves. Crude oil
production is marketed under a 30 day evergreen contract with either an end use
refinery or an intermediary. The natural gas production from the Sylvan

                                      -9-
<PAGE>

Lake Unit is sold under a long-term contract to a major netback priced pool
aggregator. The remainder of production from this property is sold at the
prevailing spot price under short-term contracts.

SUMMARY OF PRODUCTION LOCATIONS

During the year ended December 31, 2001, 84% of Enerplus' crude oil and NGLs
production and 91% of Enerplus' natural gas production came from Alberta, 2% of
Enerplus' crude oil and NGLs production and 5% of Enerplus' natural gas
production came from British Columbia, and 14% of Enerplus' crude oil and NGLs
production and 4% of Enerplus' natural gas production came from Saskatchewan.
The following table sets out the geographical areas of Enerplus' production from
its major properties in 2001 and the average daily production from such
properties during the year ended December 31, 2001:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                                                                                      TOTAL (BOE/D)
                                               CRUDE OIL               NGLS           NATURAL GAS     (6 MCF/D = 1
                LOCATION                        (BBLS/D)             (BBLS/D)           (MCF/D)          BOE/D)
----------------------------------------------------------------------------------------------------------------------
<S>                                            <C>                   <C>              <C>             <C>
ALBERTA
----------------------------------------------------------------------------------------------------------------------
   Joarcam                                        1,999                   141            7,703            3,424
----------------------------------------------------------------------------------------------------------------------
   Medicine Hat Region                                3                     -           17,011            2,838
----------------------------------------------------------------------------------------------------------------------
   Deep Basin                                         -                   519            9,501            2,103
----------------------------------------------------------------------------------------------------------------------
   Progress                                         784                   107            6,909            2,043
----------------------------------------------------------------------------------------------------------------------
   Hanna Garden                                       -                     1           10,898            1,817
----------------------------------------------------------------------------------------------------------------------
   Benjamin                                           -                    11            9,988            1,676
----------------------------------------------------------------------------------------------------------------------
   Giltedge                                       1,546                     -              597            1,646
----------------------------------------------------------------------------------------------------------------------
   Valhalla                                         377                    86            5,938            1,453
----------------------------------------------------------------------------------------------------------------------
   Pembina Five-Way / South Buck Lake             1,166                    60              732            1,348
----------------------------------------------------------------------------------------------------------------------
   Bashaw                                             -                    66            6,708            1,184
----------------------------------------------------------------------------------------------------------------------
   Pine Creek                                        11                   263            4,895            1,090
----------------------------------------------------------------------------------------------------------------------
   Kaybob                                             -                   419            3,884            1,066
----------------------------------------------------------------------------------------------------------------------
   Auburndale                                       752                     -              800              885
----------------------------------------------------------------------------------------------------------------------
   Medicine Hat Glauconite C Pool                   585                     -              844              726
----------------------------------------------------------------------------------------------------------------------
   Sylvan Lake                                      280                    97            1,717              663
----------------------------------------------------------------------------------------------------------------------
   Other                                          9,337                 2,109           72,474           23,524
----------------------------------------------------------------------------------------------------------------------
TOTAL ALBERTA                                    16,840                 3,879          160,599           47,486
----------------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------------
TOTAL BRITISH COLUMBIA                              300                    95            9,291            1,943
----------------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------------
TOTAL SASKATCHEWAN                                3,446                     4            6,781            4,580
----------------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------------
TOTAL MANITOBA                                        6                     -                -                6
----------------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------------
TOTAL                                            20,592                 3,978          176,671           54,015
----------------------------------------------------------------------------------------------------------------------
</TABLE>

LOCATION OF FACILITIES

The following tables describe the location, type of facility, working interest
of Enerplus and, where applicable, the total processing or treating capacity and
the processing or treating capacity attributable to Enerplus' working interests
in each of the facilities that are material to Enerplus' operations.

                                      -10-
<PAGE>

<TABLE>
<CAPTION>
                                                                                                      GROSS        W.I.
CRUDE OIL PRODUCTION FACILITIES                                                                      TREATING     TREATING
                                                                                                     CAPACITY     CAPACITY
AREA NAME                 TYPE OF FACILITY                                                 W.I.%     (BBLS/D)     (BBLS/D)
------------------------------------------------------------------------------------------------------------------------------
<S>                       <C>                                                              <C>       <C>          <C>
Auburndale (1)            Emulsion Treating & Water Disposal                                100%        2,000      2,000
Battle Creek (1)          Emulsion Treating & Water Disposal                                100%        6,000      6,000
Butte Unit                Emulsion Treating & Water Injection                                25%        7,200      1,800
Cadogan (1)               Emulsion Treating & Water Disposal                                100%        9,000      9,000
Chauvin (1)               Emulsion Treating & Water Disposal                                 95%       28,000     26,600
Chauvin South (1)         Emulsion Treating & Water Disposal                                100%        5,000      5,000
David (1)                 Emulsion Treating & Water Disposal                                100%       30,000     30,000
Freda Lake                Emulsion Treating & Water Injection                                30%        4,000      1,200
Gift                      Emulsion Treating                                                  24%       11,300      2,720
Giltedge (1)              Emulsion Treating & Water Disposal, Refrigeration,                100%       30,000     30,000
                          Compression
Gleneath (1)              Emulsion Treating & Water Disposal                                 47%        3,000      1,398
Hayter                    Emulsion Treating & Water Disposal                                  2%      110,800      2,560
Hayter                    Emulsion Treating & Water Disposal                                 11%       83,100      8,970
Heward (1)                Emulsion Treating & Water Disposal                                100%       18,000     18,000
Jenner                    Emulsion Treating, Water Disposal & Solution Gas Compressing       15%       25,000      3,750
Joarcam (1)               Emulsion Treating & Water Injection                                95%        2,800      2,660
Joarcam (1)               Emulsion Treating & Water Injection                                82%       10,000      8,200
Kessler (1)               Emulsion Treating & Water Disposal                                100%        6,000      6,000
Little Horse (1)          Emulsion Treating & Water Disposal                                 65%       13,775      8,954
Medicine Hat (1)          Emulsion Treating & Water Injection                                44%        8,000      3,520
Medicine Hat (1)          Emulsion Treating & Water Injection                                44%        4,000      1,760
Medicine River (1)        Emulsion Treating & Water Disposal                                 56%        2,000      1,120
Pembina Five-Way (1)      Emulsion Treating & Water Injection                               100%        7,500      7,500
                          Emulsion Treating & Water Injection                               100%        1,250      1,250
                          Emulsion Treating & Water Injection                               100%        2,500      2,500
Pouce Coupe (1)           Emulsion Treating & Water Injection                                49%        2,500      1,225
Progress (1)              Emulsion Treating & Water Injection                               100%        2,000      2,000
Shorncliffe (1)           Emulsion Treating & Water Injection                                66%       38,000     24,928
South Buck Lake (1)       Emulsion Treating & Water Injection                               100%        1,800      1,800
Sylvan Lake (1)           Emulsion Treating & Water Disposal                                100%        2,500      2,500
Valhalla (1)              Emulsion Treating & Water Disposal                                 86%        4,600      3,956
</TABLE>

NOTE:

(1)  Operated by Enerplus.

<TABLE>
<CAPTION>
                                                                                                      GROSS        W.I.
NATURAL GAS PRODUCTION FACILITIES                                                                    TREATING     TREATING
                                                                                                     CAPACITY     CAPACITY
AREA NAME                               TYPE OF FACILITY                                   W.I.%     (BBLS/D)     (BBLS/D)
------------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>                                                <C>       <C>          <C>
Bantry (1)                              Compression & dehydration                            92%       20.0          18.3
Bashaw (1)                              Compression, dehydration & processing                27%       12.0           3.2
Botha Facility                          Compression, refrigeration & dehydration             10%       16.7           1.7
Burnt Timber Gas Plant                  Refrigeration, sweetening, sulphur recovery &         3%      128.1           4.2
                                        stabilization/storage for pentanes plus
Carson Creek                            Sweetening & refrigeration                            5%       87.0           4.2
Elmworth Gas Plant                      Turboexpansion & ethane extraction                    6%      575.0          34.9
Ferrier                                 Compression & refrigeration                          29%        9.1           2.7
Ferrier (1)                             Compression & dehydration                            64%        6.0           3.8
Fox Valley (1)                          Compression & dehydration                            97%        8.0           7.7
Gilby                                   Sweetening, absorption & refrigeration                9%       71.0           6.4
Hanna Garden (1)                        Compression & dehydration                            84%       11.0          10.0
Hanna Garden (1)                        Compression & dehydration                           100%       11.0          11.0
Joarcam (1)                             Compression, dehydration & processing                99%        5.5           5.4
Joarcam (1)                             Compression, dehydration & processing                93%       10.0           9.3
</TABLE>

                                      -11-
<PAGE>

<TABLE>
<CAPTION>
                                                                                                      GROSS        W.I.
NATURAL GAS PRODUCTION FACILITIES                                                                    TREATING     TREATING
                                                                                                     CAPACITY     CAPACITY
AREA NAME                               TYPE OF FACILITY                                   W.I.%     (BBLS/D)     (BBLS/D)
------------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>                                                <C>       <C>          <C>
Joarcam (1)                             Compression, dehydration & processing                86%        9.5           8.2
Karr Gas Processing Plant               Turboexpansion & ethane extraction                    2%      110.0           2.1
Komie (1)                               Compression & dehydration                            45%        6.0           2.7
Leo Gas Plant                           Compression & refrigeration                          21%       25.2           5.4
Medicine Hat (1)                        Compression & dehydration                           100%        8.0           8.0
Medicine Hat (1)                        Compression & dehydration                           100%        4.0           4.0
Medicine River (1)                      Compression & dehydration                            49%        3.5           1.7
Minnehik Buck Lake                      Sweetening & absorption                               8%      159.5          12.9
Pine Creek Gas Plant                    Compression, refrigeration & dehydration             40%       16.0           6.4
Pine Creek (1)                          Compression & dehydration                            73%       12.0           8.8
Progress Gas Plant                      Compression, sweetening, refrigeration &             10%      140.3          14.1
                                        dehydration
Ram River                               Sweetening & refrigeration                            2%      630.0          10.1
South Wapiti Gas Plant (Shallow Cut)    Compression, refrigeration & dehydration              1%      300.0           4.0
Sylvan Lake                             Sweetening, refrigeration & absorption               14%       69.0           9.7
Sylvan Lake (1)                         Compression & dehydration                           100%        3.0           3.0
Valhalla (1)                            Compression & dehydration                            86%        6.0           5.2
Valhalla (1)                            Compression, dehydration & processing                35%        6.0           2.1
Valhalla Burnt River Gas Processing     Compression, refrigeration & dehydration             11%       32.0           3.4
Verger (1)                              Compression & dehydration                           100%       12.0          12.0
Wapiti Deep Cut Plant                   Turboexpansion & ethane extraction                    3%      355.8          11.1
Wapiti Gas Plant (Shallow Cut)          Compression, refrigeration & dehydration              3%      120.0           3.5
</TABLE>

NOTE:

(1)  Operated by Enerplus.

DRILLING ACTIVITIES AND RESULTS

During 2001, Enerplus participated in the drilling of 546 gross wells (321.6 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 drilling for
the years ended December 31, 2001 and 2000. 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.

<TABLE>
<CAPTION>
                                                YEAR ENDED DECEMBER 31,
                                     --------------------------------------------
                                              2001                   2000
                                     --------------------------------------------
<S>                                   <C>          <C>       <C>         <C>
DEVELOPMENT WELLS                     GROSS(1)     NET(2)    GROSS(1)    NET(2)
                                     --------------------------------------------
  Oil                                   104         37.7       103        33.5
  Natural Gas                           429        279.4       184        53.9
  Dry                                    13          4.5        15         3.4
                                     --------------------------------------------
Total working interest wells (3)        546        321.6       302        90.8
                                     --------------------------------------------
                                     --------------------------------------------
</TABLE>

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 interest therein.

(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.

                                      -12-
<PAGE>

OIL AND NATURAL GAS WELLS AND LEASE HOLDINGS

The following table summarizes, as at December 31, 2001, Enerplus' interests in
producing and shut-in wells which it believes are capable of production, along
with Enerplus' interests in undeveloped oil and natural gas leases and rights:

<TABLE>
<CAPTION>
                               PRODUCING WELLS                      SHUT-IN WELLS(1)                   ACRES
                     ------------------------------------- ------------------------------------ ---------------------
                           OIL            NATURAL GAS             OIL           NATURAL GAS           (000'S)
                     ----------------- ------------------- ------------------ -----------------
AREA                 GROSS(2)  NET(3)  GROSS(2)   NET(3)   GROSS(2)  NET(3)   GROSS(2)  NET(3)  GROSS(2)    NET(3)
-------------------  --------- ------- ---------- -------- --------- -------- --------- ------- ---------- ----------
<S>                  <C>       <C>     <C>        <C>      <C>       <C>      <C>       <C>     <C>        <C>
Alberta                2,642    1,131    3,732     1,725      489     162         306     97       820.0       408.6
British Columbia          34       12       87        19       11       3          44     13       118.7        51.5
Saskatchewan           2,325      478      305       211      376     103           8      1        36.6        25.6
                     --------- ------- ---------- -------- --------- -------- --------- ------- ---------- ----------
Total                  5,001    1,621    4,124     1,955      876     268         358    111       975.3       485.7
                     --------- ------- ---------- -------- --------- -------- --------- ------- ---------- ----------
                     --------- ------- ---------- -------- --------- -------- --------- ------- ---------- ----------
</TABLE>

NOTES:

(1)  "Shut-In" wells means wells which are not producing but which may be
     capable of production. Shut-in wells in which Enerplus has an interest are
     located no further than 10 kilometres from gathering systems, pipelines or
     other means of transportation. See "Description of Principal Properties".

(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.

RESERVES RECONCILIATION

The table below reconciles the oil and natural gas reserves of Enerplus from
December 31, 2000 (being the reserves of EnerMark Income Fund at such time) to
December 31, 2001.

<TABLE>
<CAPTION>
                                                                                                                      ESTABLISHED
                                CRUDE OIL             NATURAL GAS                NGLS                   TOTAL           RESERVES
                                 (MBBLS)                 (MMCF)                 (MBBLS)                (MBOE)            (MBOE)
                           -------------------------------------------------------------------------------------------------------
                            Proven   PROBABLE(1)   Proven   PROBABLE(1)   Proven   PROBABLE(1)   Proven   PROBABLE(1)
                           ------------------------------------------------------------------------------------------
<S>                        <C>       <C>         <C>        <C>           <C>      <C>          <C>       <C>         <C>
Opening reserves as of
December 31, 2000          57,221       31,036   655,416      183,532     11,399      3,062     177,856      64,687      210,199
Production                 (7,516)           0   (64,485)           0     (1,452)         0     (19,716)          0      (19,716)
Acquisitions (2)           46,858       11,400   307,763       84,441      5,582        417     103,734      25,891      116,680
Divestments                (4,163)      (1,616)  (16,977)      (6,540)      (344)       (64)     (7,337)     (2,770)      (8,722)
Drilling, Development and
Revisions                   2,447       (3,177)   69,416         (744)       929      1,259      14,945      (2,043)      13,924
                           -------------------------------------------------------------------------------------------------------
Year-end reserves as at
December 31, 2001          94,847       37,643   951,133      260,689     16,114      4,674     269,482      85,765      312,365
                           -------------------------------------------------------------------------------------------------------
                           -------------------------------------------------------------------------------------------------------
</TABLE>

NOTES:

(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.

(2) Includes reserve acquisitions attributable to the Merger.

HISTORICAL PRODUCTION REVENUES

Gross production revenues (before deduction of royalties payable to others) for
each of Enerplus' products during the years ended December 31, 2001 and 2000 are
as follows:

<TABLE>
<CAPTION>
                                                   2001                                2000
                                       ------------------------------------------------------------------
                                                         % OF TOTAL                          % OF TOTAL
                                        $ MILLION          REVENUE         $ MILLION          REVENUE
                                       ------------------------------------------------------------------
                 <S>                    <C>              <C>               <C>               <C>
                 Crude Oil                 $234.5                37%           $149.0              44%
                 NGLs                        45.2                 7%             25.0               7%
                 Natural gas                359.7                56%            169.2              49%
                                       ------------------------------------------------------------------
                 Total                     $639.4               100%           $343.2             100%
                                       ------------------------------------------------------------------
                                       ------------------------------------------------------------------
</TABLE>

                                      -13-
<PAGE>

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

<TABLE>
<CAPTION>
                                                                        2001
                                 ----------------------------------------------------------------------------------
                                     FIRST           SECOND             THIRD           FOURTH          TOTAL FOR
                                    QUARTER          QUARTER           QUARTER          QUARTER            YEAR
                                 -------------    -------------     -------------    -------------    -------------
<S>                                 <C>              <C>               <C>              <C>             <C>
Crude oil
  Light/medium (Bbls/d)              14,273           13,425            16,535           17,468            15,437
  Heavy (Bbls/d)                      4,513            4,561             5,933            5,593             5,155
                                 -------------    -------------     -------------    -------------    -------------
Total crude oil (Bbls/d)             18,786           17,986            22,468           23,061            20,592
NGLs (Bbls/d)                         3,127            3,936             4,559            4,272             3,978
                                 -------------    -------------     -------------    -------------    -------------
Total liquids (Bbls/d)               21,913           21,922            27,027           27,333            24,570
                                 -------------    -------------     -------------    -------------    -------------
Natural gas (Mcf/d)                 152,367          149,201           199,823          204,467           176,671
                                 -------------    -------------     -------------    -------------    -------------
Total (BOE/d)                        47,308           46,789            60,331           61,411            54,015
                                 -------------    -------------     -------------    -------------    -------------
</TABLE>

<TABLE>
<CAPTION>
                                                                        2000
                                 ----------------------------------------------------------------------------------
                                     FIRST           SECOND             THIRD           FOURTH          TOTAL FOR
                                    QUARTER          QUARTER           QUARTER          QUARTER            YEAR
                                 -------------    -------------     -------------    -------------    -------------
<S>                                 <C>              <C>               <C>              <C>             <C>
Crude oil
  Light/medium (Bbls/d)               6,236            7,558             7,762            8,610             7,546
  Heavy (Bbls/d)                      4,470            4,929             4,812            3,966             4,543
                                 -------------    -------------     -------------    -------------    -------------
Total crude oil (Bbls/d)             10,706           12,487            12,574           12,576            12,089
NGLs (Bbls/d)                         1,695            2,101             1,856            2,790             2,111
                                 -------------    -------------     -------------    -------------    -------------
Total liquids (Bbls/d)               12,401           14,588            14,430           15,366            14,200
                                 -------------    -------------     -------------    -------------    -------------
Natural gas (Mcf/d)                  81,153           93,444           104,045          126,943           101,473
                                 -------------    -------------     -------------    -------------    -------------
Total (BOE/d)                        25,927           30,162            31,771           36,523            31,112
                                 -------------    -------------     -------------    -------------    -------------
</TABLE>

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)

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31, 2001
                                 ----------------------------------------------------------------------------------
                                     FIRST           SECOND             THIRD           FOURTH          TOTAL FOR
                                    QUARTER          QUARTER           QUARTER          QUARTER            YEAR
                                 -------------    -------------     -------------    -------------    -------------
<S>                                 <C>              <C>               <C>              <C>             <C>
Sales price                          $35.13           $33.58            $33.62           $21.63            $30.58
Hedging gains (costs)                  -               (0.78)            (0.63)            3.41              0.61
Royalties                             (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            $18.03
                                 -------------    -------------     -------------    -------------    -------------
                                 -------------    -------------     -------------    -------------    -------------
Average selling price
  Crude oil
     Light/medium                    $37.10           $36.86            $37.95           $24.04            $33.55
     Heavy                           $20.93           $22.34            $27.20           $14.39            $21.27
     Total crude oil                 $33.22           $33.18            $35.11           $21.70            $30.48
  NGLs                               $46.61           $35.44            $26.29           $21.23            $31.12
</TABLE>

                                      -14-
<PAGE>

<TABLE>
<CAPTION>
                                                            YEAR ENDED DECEMBER 31, 2000
                                 ----------------------------------------------------------------------------------
                                     FIRST           SECOND             THIRD           FOURTH          TOTAL FOR
                                    QUARTER          QUARTER           QUARTER          QUARTER            YEAR
                                 -------------    -------------     -------------    -------------    -------------
<S>                                 <C>              <C>               <C>              <C>             <C>
Sales price                          $34.81           $34.79            $38.90           $32.90            $35.33
Hedging gains (costs)                 (1.57)           (1.58)            (2.10)           (2.13)            (1.86)
Royalties                             (7.38)           (7.21)            (7.97)           (6.62)            (7.28)
Operating costs(1)                    (4.74)           (6.05)            (6.33)           (6.53)            (5.97)
                                 -------------    -------------     -------------    -------------    -------------
Netback                              $21.12           $19.95            $22.50           $17.62            $20.22
                                 -------------    -------------     -------------    -------------    -------------
                                 -------------    -------------     -------------    -------------    -------------
Average selling price
  Crude oil
     Light/medium                    $38.67           $37.36            $41.06           $36.49            $38.34
     Heavy                           $32.31           $32.32            $35.53           $25.79            $31.74
     Total crude oil                 $36.01           $35.37            $38.95           $33.11            $35.86
  NGLs                               $27.22           $31.37            $38.60           $31.95            $32.33
</TABLE>

NATURAL GAS NETBACKS ($ PER MCF)

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31, 2001
                                 ----------------------------------------------------------------------------------
                                     FIRST           SECOND             THIRD           FOURTH          TOTAL FOR
                                    QUARTER          QUARTER           QUARTER          QUARTER            YEAR
                                 -------------    -------------     -------------    -------------    -------------
 <S>                                <C>              <C>               <C>              <C>             <C>
Sales price                          $ 8.59           $ 5.81            $ 3.43           $ 3.01            $ 4.91
Hedging gains (costs)                 (0.21)            0.01              1.03             1.51              0.69
Royalties                             (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
                                 -------------    -------------     -------------    -------------    -------------
                                 -------------    -------------     -------------    -------------    -------------
</TABLE>

<TABLE>
<CAPTION>
                                                            YEAR ENDED DECEMBER 31, 2000
                                 ----------------------------------------------------------------------------------
                                     FIRST           SECOND             THIRD           FOURTH          TOTAL FOR
                                    QUARTER          QUARTER           QUARTER          QUARTER            YEAR
                                 -------------    -------------     -------------    -------------    -------------
<S>                                 <C>              <C>               <C>              <C>             <C>
Sales price                          $ 2.56           $ 3.18            $ 4.43           $ 6.81            $ 4.52
Hedging gains (costs)                  0.08            (0.02)            (0.01)            0.10              0.04
Royalties                             (0.69)           (0.69)            (1.25)           (1.73)            (1.16)
Operating costs(1)                    (0.65)           (0.56)            (0.71)           (0.66)            (0.65)
                                 -------------    -------------     -------------    -------------    -------------
Netback                              $ 1.30           $ 1.91            $ 2.46           $ 4.52            $ 2.75
                                 -------------    -------------     -------------    -------------    -------------
                                 -------------    -------------     -------------    -------------    -------------
</TABLE>

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.

<TABLE>
<CAPTION>
                                                                               2001
                                             -------------------------------------------------------------------------
($ 000'S)                                        FIRST         SECOND         THIRD          FOURTH       TOTAL FOR
                                                QUARTER        QUARTER        QUARTER        QUARTER         YEAR
                                             -------------  -------------  -------------  ------------- --------------
<S>                                             <C>           <C>            <C>            <C>          <C>
Development drilling and completions            $ 8,529       $ 19,218       $ 25,941       $ 29,316       $ 83,004
Plant and facilities                             14,006          6,981         15,190         17,417         53,594
Office and other expenditures                     1,448          2,899            771          1,564          6,682
                                             -------------  -------------  -------------  ------------- --------------
                                                 23,983         29,098         41,902         48,297        143,280
Producing property acquisitions                     367          2,388         57,214         17,463         77,432
                                             -------------  -------------  -------------  ------------- --------------
Total capital expenditures                       24,350         31,486         99,116         65,760        220,712
Property dispositions                            (9,427)       (10,548)       (34,826)       (13,695)       (68,496)
                                             -------------  -------------  -------------  ------------- --------------
Net capital expenditures                        $14,923       $ 20,938       $ 64,290       $ 52,065       $152,216
                                             -------------  -------------  -------------  ------------- --------------
                                             -------------  -------------  -------------  ------------- --------------
</TABLE>

                                      -15-
<PAGE>

<TABLE>
<CAPTION>
                                                                               2000
                                             -------------------------------------------------------------------------
($ 000'S)                                        FIRST         SECOND         THIRD          FOURTH       TOTAL FOR
                                                QUARTER        QUARTER        QUARTER        QUARTER         YEAR
                                             ------------- --------------  ------------- -------------- --------------
<S>                                             <C>            <C>            <C>           <C>           <C>
Development drilling and completions            $ 9,306        $ 3,803        $ 4,731       $  9,262       $ 27,102
Plant and facilities                              1,189          5,417          1,730          3,525         11,861
Office and other expenditures                       461            140            221            211          1,033
                                             ------------- --------------  ------------- -------------- --------------
                                                 10,956          9,360          6,682         12,998         39,996
Producing property acquisitions                  37,168          3,196          7,659          3,086         51,109
                                             ------------- --------------  ------------- -------------- --------------
Total capital expenditures                       48,124         12,556         14,341         16,084         91,105
Property dispositions                              (481)        (5,121)        (7,385)       (12,274)       (25,261)
                                             ------------- --------------  ------------- -------------- --------------
Net capital expenditures                        $47,643        $ 7,435        $ 6,956       $  3,810       $ 65,844
                                             ------------- --------------  ------------- -------------- --------------
                                             ------------- --------------  ------------- -------------- --------------
</TABLE>

EXPLORATION AND DEVELOPMENT

The primary 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 be concentrated 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. Enerplus received an average price before hedging
of $30.48/Bbl for its crude oil and $31.12/Bbl for its NGLs for the year ended
December 31, 2001, compared to $35.86/Bbl for crude oil and $32.33/Bbl of NGLs
for the year ended December 31, 2000.

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 revenues attributable to natural gas has risen over the past five
years from 30% in 1997 to 56% in 2001. The average price received by Enerplus,
before hedging, for its natural gas in 2001 was $4.91/Mcf compared to $4.52/Mcf
in the year ended December 31, 2000.

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, the crude oil, NGLs and 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. See
"Risk Factors - Oil and Natural Gas Prices". Information regarding Enerplus'
financial instruments is contained in Note 8 to Enerplus' audited annual
consolidated financial statements for the year ended December 31, 2001 and under
the heading "Pricing and Price Risk Management" in the Fund's management
discussion and analysis for the year ended December 31, 2001 and which is
contained on page 36 of the Fund's 2001 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

                                      -16-
<PAGE>

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 it capital expenditure budget to continue to meet environmental
protection requirements. The costs incurred by Enerplus for compliance with
environmental matters and site restoration costs amounted to approximately 2% of
the total development expenditures incurred by Enerplus in 2001. Since the
environmental standards and regulations to which Enerplus is subject apply to
all participants in the oil and gas industry, it is not anticipated that
Enerplus' competitive position within the industry will be adversely affected.
See "Risk Factors - Environmental Concerns".

                          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 83% 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 and are included as "minor" properties in the Sproule
Report. The constant price cases contained herein were extracted from a separate
report prepared by Sproule dated March 7, 2002 which was based upon the
escalated case Sproule Report.

In preparing its report, Sproule obtained basic information from Enerplus, which
included 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
proved reserves and the probable reserves portion that has been reduced by a
risk factor of 50%. As a consequence, our production volumes and reserve
estimates may not be comparable to those made by United States companies.

The following is a summary, as at January 1, 2002, 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. 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 MANAGEMENT FEES AND INDIRECT COSTS 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

                                      -17-
<PAGE>

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.

  OIL AND NATURAL GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE CASH FLOWS
            INCLUDING ARTC BASED ON ESCALATED PRICE ASSUMPTIONS(11)

<TABLE>
<CAPTION>
                                                                                   PRESENT VALUE OF ESTIMATED FUTURE NET CASH FLOW,
                                      WORKING INTEREST RESERVES(1)                            $000 DISCOUNTED AT RATES OF:
                          -------------------------------------------------------  ------------------------------------------------
                                     GROSS                      NET
                          ---------------------------  --------------------------
                            OIL       GAS      NGLS      OIL      GAS      NGLS
                           MBBLS      MMCF     MBBLS    MBBLS     MMCF     MBBLS      0%           10%          15%          20%
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
<S>                       <C>      <C>         <C>     <C>       <C>       <C>     <C>          <C>          <C>          <C>
Proven Reserves(2)
  Developed
    Producing(3)(4)        86,770    722,692   13,685   78,085   570,157    9,567  2,992,588    1,376,940    1,116,058      946,568
  Developed
    Non-Producing(3)(5)       620     58,791      512      540    47,233      352    157,757       78,807       63,970       54,201
  Undeveloped (6)           7,457    169,650    1,917    6,311   142,109    1,347    401,713      170,532      118,996       84,367
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
Total Proven Reserves      94,847    951,133   16,114   84,936   759,499   11,266  3,552,058    1,626,279    1,299,024    1,085,136
Probable Reserves
  at 50%(7)                18,821    130,345    2,337   15,830   106,940    1,657    644,955      159,099      106,027       75,323
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
Established Reserves      113,668  1,081,478   18,451  100,766   866,439   12,923  4,197,013    1,785,378    1,405,051    1,160,459
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
</TABLE>

  OIL AND NATURAL GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE CASH FLOWS
             INCLUDING ARTC BASED ON CONSTANT PRICE ASSUMPTIONS(12)

<TABLE>
<CAPTION>
                                                                                   PRESENT VALUE OF ESTIMATED FUTURE NET CASH FLOW,
                                      WORKING INTEREST RESERVES(1)                            $000 DISCOUNTED AT RATES OF:
                          -------------------------------------------------------  ------------------------------------------------
                                     GROSS                      NET
                          ---------------------------  --------------------------
                            OIL       GAS      NGLS      OIL      GAS      NGLS
                           MBBLS      MMCF     MBBLS    MBBLS     MMCF     MBBLS       0%          10%          15%          20%
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
<S>                       <C>      <C>         <C>     <C>       <C>       <C>     <C>          <C>          <C>          <C>
Proven Reserves(2)
    Developed              81,222    708,955   13,485   73,302   558,990    9,432  2,040,855    1,088,148      904,741      781,039
      Producing(3)(4)
    Developed                 604     57,899      508      527    46,461      349    110,681       62,525       52,084       44,929
      Non-Producing(3)(5)
    Undeveloped (6)         7,397    166,003    1,730    6,320   139,485    1,218    265,004      111,269       74,803       49,828
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
 Total Proven Reserves     89,223    932,857   15,723   80,149   744,936   10,999  2,416,540    1,261,942    1,031,628      875,796
 Probable Reserves at      16,662    129,770    2,334   14,138   106,548    1,656    336,976      100,586       67,464       47,619
   50%(7)
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
 Established Reserves     105,885  1,062,627   18,057   94,287   851,484   12,655  2,753,516    1,362,528    1,099,092      923,415
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
                          -------  ---------  -------  -------  --------  -------  ---------    ---------    ---------    ---------
</TABLE>

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, 2002, these reserves were on production
     and represent approximately 76% of Enerplus' total proven and risked
     probable oil and NGLs reserves and 67% of Enerplus' total 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

                                      -18-
<PAGE>

     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, 2002.

(9)  Natural gas reserves are reported at a base pressure of 14.65 pounds per
     square inch and a base temperature of 60(0)F.

(10) Prices for oil F.O.B. Edmonton are based upon 40(0) 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 60(0)F. The wellhead
     oil prices were adjusted for quality and 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:

<TABLE>
<CAPTION>
                                                NATURAL GAS LIQUIDS                             NATURAL GAS
                        EDMONTON    ---------------------------------------------  --------------------------------------
             WTI       PAR PRICE                           EDMONTON                              PLANT GATE
           CUSHING     40(DEGREE)   PLANT GATE  ---------------------------------  --------------------------------------
 YEAR      OKLAHOMA        API        ETHANE    PROPANE     BUTANE    PENTANES        ALBERTA       SASK.         B.C.
---------------------------------------------------------------------------------  --------------------------------------
           (US$/BBL)    ($/BBL)      ($/BBL)    ($BBL)      ($/BBL)   ($/BBL)        ($/MMBTU)    ($/MMBTU)    ($/MMBTU)
<S>        <C>         <C>          <C>         <C>         <C>       <C>            <C>          <C>          <C>
 2002        19.90        29.86        10.54      16.73       17.81     30.59           3.63         3.70         3.75
 2003        20.64        30.96        12.04      17.34       18.46     31.71           4.18         4.25         4.30
 2004        21.12        31.67        12.08      17.74       18.88     32.43           4.19         4.26         4.26
 2005        21.44        32.15        12.08      18.01       19.17     32.93           4.18         4.26         4.26
 2006        21.76        32.65        12.29      18.29       19.47     33.44           4.25         4.34         4.34
 2007        22.08        33.14        12.51      18.56       19.76     33.94           4.32         4.41         4.41
 2008        22.42        33.65        12.73      18.85       20.06     34.46           4.40         4.49         4.49
 2009        22.75        34.16        12.95      19.13       20.37     34.98           4.48         4.57         4.57
 2010        23.09        34.68        13.18      19.42       20.68     35.51           4.57         4.66         4.66
 2011        23.44        35.20        13.41      19.72       20.99     36.05           4.65         4.74         4.74
 2012        23.79        35.74        13.64      20.02       21.31     36.60           4.73         4.82         4.82
 2013        24.15        36.28        13.87      20.32       21.63     37.15           4.82         4.91         4.91
Escalation Rate of 1.5% thereafter
</TABLE>

(12) The constant price and cost case assumes the continuance of product prices
     at December 31, 2001 and operating costs projected for 2002, 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:

<TABLE>
          <S>                      <C>                               <C>
          Oil                      Edmonton Par Price 40(Degree)     $30.35
                                   API ($/bbl)

          Natural Gas:             Alberta ($/MMBTU)                  $3.58
                                   Saskatchewan ($/MMBTU)             $3.80
                                   British Columbia ($/MMBTU)         $3.90

          Natural Gas Liquids:     Ethane ($/bbl)                     $9.91
                                   Propane ($/bbl)                   $13.34
                                   Butane ($/bbl)                    $15.47
                                   Pentanes ($/bbl)                  $30.14
</TABLE>

(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 $256.6 million, of which $94.7 million is required in 2002
     and $33.2 million is required in 2003. Capital expenditures required to
     achieve the future net revenue attributable to Probable Reserves in the
     escalated price and cost case are estimated to be $146.2 million, of which
     $23.3 million is required in 2002 and $24.8 million is required in 2003.

(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 $210.4 million of which $93.6 million is required in 2002
     and $31.5 million is required in 2003. Capital expenditures required to
     achieve the future net revenue attributable to Probable Reserves in the
     constant price and cost case are estimated to be $125.9 million, of which
     $18.3 million is required in 2002 and $24.9 million is required in 2003.

(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.

                                      -19-
<PAGE>

         ESTIMATED FUTURE NET PRE-TAX CASH FLOWS ESTABLISHED RESERVES(1)
                         ESCALATING COST AND PRICE CASE
                         ($000'S EXCEPT FOR PRODUCTION)
<TABLE>
<CAPTION>
                                                    NET REVENUE                                            NET CASH
                 ANNUAL      COMPANY                   AFTER                     NET           NET        FLOW BEFORE
               PRODUCTION    INTEREST    ROYALTY      ROYALTY     OPERATING   PRODUCTION     CAPITAL        INCOME
    YEAR         (MBOE)     REVENUE(2)   BURDENS      BURDENS      EXPENSES    REVENUE(3)   INVESTMENT    TAXES(4)(5)
-----------   -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
<S>            <C>          <C>         <C>         <C>          <C>          <C>          <C>           <C>
2002             24,399       514,970     104,457      410,513      125,938      284,575      106,359        178,216
2003             24,692       589,474     119,780      469,694      132,208      337,486       45,588        291,899
2004             22,876       561,889     109,335      452,555      131,308      321,247       43,511        277,736
2005             20,683       513,592      97,039      416,553      127,491      289,062       14,198        274,864
2006             18,491       470,253      86,801      383,452      122,915      260,537        2,201        258,336
2007             16,430       426,571      77,405      349,166      117,344      231,822        3,010        228,813
2008             14,553       386,389      68,896      317,493      110,064      207,429        2,849        204,581
2009             12,984       351,184      61,297      289,887      104,026      185,861        3,315        182,547
2010             11.717       322,868      55,542      267,326       99,092      168,234        2,578        165,657
2011             10,747       299,798      51,358      248,440       92,323      156,118        2,445        153,673
Remaining       134,793     5,179,032     686,554    4,492,477    2,408,114    2,084,362      103,666      1,980,691
              -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
TOTAL:          312,365     9,616,020   1,518,464    8,097,556    3,570,823    4,526,733      329,720      4,197,013
              -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
              -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
</TABLE>

Cash Flow Before Income Taxes Discounted to January(5) 1, 2002 at:
<TABLE>
         <S>     <C>
         10%:    $1,785,378
         15%:    $1,405,051
         20%:    $1,160,459
</TABLE>

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)
<TABLE>
<CAPTION>
                                                    NET REVENUE                                            NET CASH
                 ANNUAL      COMPANY                   AFTER                     NET           NET        FLOW BEFORE
               PRODUCTION    INTEREST     ROYALTY     ROYALTY     OPERATING   PRODUCTION     CAPITAL        INCOME
    YEAR         (MBOE)     REVENUE(2)    BURDENS     BURDENS      EXPENSES    REVENUE(3)   INVESTMENT    TAXES(4)(5)
-----------   -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
<S>            <C>          <C>         <C>         <C>          <C>          <C>          <C>           <C>
2002              24,345      510,297     105,267      405,030      125,170      279,861      102,709        177,152
2003              24,396      514,492     105,493      408,999      127,671      281,328       44,010        237,318
2004              22,584      477,030      93,116      383,914      124,712      259,202       41,109        218,093
2005              20,353      429,537      80,889      348,648      118,143      230,505       14,379        216,126
2006              18,018      382,047      69,835      312,212      109,646      202,566        3,677        198,890
2007              15,928      338,224      60,552      277,672      101,625      176,047        3,228        172,819
2008              14,091      299,450      52,471      246,979       93,447      153,533        2,215        151,318
2009              12,619      268,541      45,939      222,602       87,928      134,675        1,969        132,706
2010              11,370      242,054      40,793      201,261       82,404      118,857        2,022        116,835
2011              10,445      221,358      37,027      184,331       75,908      108,424        2,335        106,089
Remaining        126,898    2,815,009     375,708    2,439,301    1,357,476    1,081,821       55,650      1,026,170
              -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
TOTAL:           301,047    6,498,039   1,067,090    5,430,949    2,404,130    3,026,819      273,303      2,753,516
              -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
              -----------  -----------  ----------  -----------  -----------  -----------  ------------  -------------
</TABLE>

Cash Flow Before Income Taxes Discounted(5) to January 1, 2002 at:
<TABLE>
         <S>    <C>
         10%:   $1,362,528
         15%:   $1,099,092
         20%:     $923,415
</TABLE>

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.

                                      -20-
<PAGE>

                 INFORMATION RESPECTING ENERPLUS RESOURCES FUND

OPERATIONS OF ENERPLUS

MANAGEMENT POLICIES AND ACQUISITION STRATEGY

EGEM manages the Fund, EnerMark, Enerplus and any other of the Fund's
subsidiaries pursuant to the Management Agreement. The board of directors of
EnerMark, as the publicly-elected body which oversees the business and affairs
of Enerplus, has retained EGEM to provide comprehensive management services and
has delegated certain authority to EGEM to administer and regulate the
day-to-day operations of Enerplus and to make executive decisions which conform
to general policies and general principles established by the board of directors
of EnerMark. The Management Agreement also provides that EGEM is to undertake
all matters pertaining to the properties on behalf of Enerplus' operating
subsidiaries. All activities undertaken by EGEM 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 ensures that EGEM utilizes its extensive
experience and employs prudent oil and gas business practices to increase the
value of the assets of Enerplus through the acquisition of producing oil and gas
properties.

Enerplus selectively acquires producing oil and natural gas properties with
development opportunities that are considered to be of a low risk nature in the
oil and gas industry. Credit facilities are maintained which enable Enerplus to
pursue the purchase of additional properties as opportunities arise.

EGEM may present Enerplus with opportunities to acquire properties and assets
which Enerplus may be interested in acquiring and which are consistent with the
guidelines for acquisitions which may be established from time to time by the
board of directors of EnerMark. In addition, as part of the services provided by
EGEM to Enerplus, EGEM may recommend that Enerplus enter into agreements to
dispose of oil and natural gas properties and make farmouts and other
dispositions of such properties. Any asset or property acquisition or
disposition with a value of greater than $10 million requires the approval of
the directors of EnerMark.

Enerplus ensures that the strategy employed by EGEM maximizes the level of
sustainable production of oil and natural gas from Enerplus' existing properties
and supplements production by reserve acquisitions and development. Capital
expenditures are focused on development activity as opposed to exploration.
Certain exploration properties may be sold, farmed out or developed emphasizing
the use of third party resources.

DISTRIBUTABLE INCOME

Unitholders of record on a distribution record date, currently established by
Enerplus as the 10th of each calendar month (with the exception of January, for
which the distribution record date is December 31st of the prior year), will be
entitled to receive distributions which are paid by Enerplus to those
unitholders on the corresponding distribution payment date, currently
established as the 20th of each calendar month. Each unitholder's share of the
income distributed by the Fund is equal to the proportionate share per Trust
Unit multiplied by the number of Trust Units owned of record by the unitholder
on that distribution record date. Distributable income consists of both the net
income of the Fund (being all royalty, interest, dividend and other income
received by the Fund from its operating subsidiaries less all expenses of the
Fund (including the general and administrative expenses of the Fund) chargeable
against that income) and the net realized capital gains of the Fund. Enerplus
may, on or before any distribution record date, declare payable to the
unitholders on that distribution record date, all or any part of the net income
and net realized capital gains of the Fund to the extent not previously declared
payable, for that period ending on the distribution record date. 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 INCOME TAX ACT (Canada) (other
than paragraph 82(1)(b) thereof) plus any net realized capital gains of the
Fund, to the extent that either is not previously declared payable by Enerplus
to its unitholders in such fiscal year, shall be payable to unitholders
immediately prior to the end of that fiscal year. Notwithstanding the foregoing,
the amount of net income and net realized capital gains of the Fund that is

                                      -21-
<PAGE>

determined to be required to be retained by the Fund in order to pay any tax
liability of the Fund shall not be payable by the Fund to unitholders.

See "Distributions to Unitholders" for the past cash distributions made or
declared to unitholders of Enerplus.

ENVIRONMENTAL OBLIGATIONS

Enerplus emphasizes the importance of creating and maintaining a safe and
environmentally sound operation by focusing on proper training of field
operators, continuous and thorough review of operating procedures and policies
conducted by the field operations staff and management and by monitoring and
ensuring compliance with safety and environmental regulations.

Enerplus regularly conducts safety and environment training for the field
foremen and operations staff, who then implement this training in the field with
employees and other operators. Production optimization, operator training and
development, and orientation programs are held which include such topics as
emergency response, media relations, first aid and CPR, and oil spill training.
Occupational health and safety, environmental regulations, site remediation and
waste handling training are also included to continually improve the knowledge
and expertise of the personnel employed by EGEM to oversee the operations of
Enerplus.

ACQUISITION DUE DILIGENCE

Enerplus conducts thorough due diligence on all prospective acquisitions. Site
inspections, file reviews and soil and ground-water sampling, if required, are
conducted by environmental consultants and/or an internal team from Enerplus.
Potential contamination and operational issues are identified at this stage to
help protect Enerplus from purchasing properties with significant environmental
liabilities.

SITE INSPECTIONS PROGRAM

As part of its regular due diligence program, Enerplus conducts both internal
and third party site inspections at selected facilities each year. In addition,
in 2001 Enerplus implemented an inspection program for construction and drilling
projects. These inspections review issues relating to environment and safety
regulations, industry practices and company and operational practices.

SPILL AND INCIDENT CONTROL

Enerplus field staff are required to report all spills, incidents and near
misses to the Environment and Safety department for review. The review of such
incidents allows Enerplus to determine the factors responsible and assist in the
identification of other similar situations prior to any incidents occurring.
Overall, Enerplus is confident that the program will reduce the occurrence of
spills and prevent future losses.

AIR EMISSIONS - FLARING AND BENZENE

The Alberta Energy and Utilities Board (the "EUB") released flaring guidelines
which require that companies work to reduce and improve the efficiency of
solution gas flaring and consult with residents, especially those living within
500 metres of solution gas flare installations at crude oil or crude bitumen
batteries. Enerplus has been actively reviewing all its flare sites and is
confident that it will meet the EUB guidelines as required by the end of 2002.

Enerplus implemented monitoring of its glycol dehydrators as part of the
voluntary program for addressing benzene emissions in its operations. Enerplus
had previously begun the inventory and calculation of benzene emissions,
however, due to new acquisitions in 2000 and 2001, additional properties
required investigation. Information has been collected on all glycol dehydrators
and those that do not meet the guidelines will require additional investigation
by a third party consultant, towards retrofitting them to bring them into
compliance in 2002. Others will continue to be monitored to ensure they remain
within compliance of the guidelines.

                                      -22-
<PAGE>

INSURANCE

Enerplus carries insurance coverage to protect its assets at or above the
standards applied within the oil and natural gas industry. Coverages are
determined and placed by Enerplus subsequent to giving consideration to 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 acting in good faith in these capacities on
behalf of Enerplus.

BORROWING

The Fund may, provided that the approval of the board of directors of EnerMark
has been obtained, borrow, incur indebtedness, give any guarantee or enter into
any subordination agreement on behalf of the Fund or of any other person, 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 entity, EnerMark. Details of these banking arrangements are
contained in Note 3 of Enerplus' audited annual consolidated financial
statements for the year ended December 31, 2001 and under the heading "Liquidity
and Capital Resources" in Enerplus' management discussion and analysis,
contained on page 45 of the Fund's 2001 Annual Report, each of which sections is
incorporated herein by reference.

RECORDS

EGEM, on behalf of the Trustee, keeps such 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 shall at all times have access to such
records to the same extent as though they were shareholders of such a
corporation. All such records are kept by EGEM at its office in Calgary,
Alberta.

PERSONNEL

As at December 31, 2001, Enerplus (including the personnel of EGEM who devote a
significant portion of their time to the affairs of Enerplus) employed a total
of 391 persons.

DESCRIPTION OF THE TRUST UNITS AND THE TRUST INDENTURE

GENERAL

The Fund is authorized to issue an unlimited number of Trust Units pursuant to
the Trust Indenture. The Trust Units represent equal undivided beneficial
interests 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 evidences of 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

                                      -23-
<PAGE>

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.

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 EGEM 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 duly 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 shall promptly appoint
a successor trustee. If the Trustee resigns or is removed by unitholders, its
successor must be approved by 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 EGEM or any authorized delegate. These provisions, however,
shall 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.

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 INCOME TAX ACT
(Canada) 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 INCOME TAX ACT (Canada). At
present, the sole assets of the Fund are all of the outstanding shares of
EnerMark (which owns all of the shares of ERC), unsecured indebtedness issued to
the Fund by EnerMark and the 95% and 99% royalty interests issued to the Fund by
EnerMark and ERC, respectively. The Fund may invest cash which is not being used
immediately for the purposes required in the Trust

                                      -24-
<PAGE>

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's distributable income is distributed to the unitholders by EGEM on
behalf of the Fund on the date which is either on or within 30 days after (and
in the same calendar year as) the corresponding distribution record date. The
Fund has established 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, with the exception of the January 20th payment date which is
preceded by a record date of December 31st. See "Information Respecting Enerplus
Resources Fund Operations of Enerplus - Distributable Income" and "Distributions
to Unitholders". In 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, include a distribution of Trust Units having a value equal to the cash
shortfall.

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 EGEM on behalf of the Trustee.

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 shall 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 shall
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 other material agreements of Enerplus, the Fund's
unitholders are entitled to nominate all but three of 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 duly called 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 duly called 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 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.

                                      -25-
<PAGE>

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 the directors of
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 the board of directors of 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, EGEM has been retained by the Fund and its subsidiaries to manage
and administer the business and affairs of the Fund and manage the operations,
business and affairs of the Fund's subsidiaries, subject to the supervision of
the directors of EnerMark. See "Information Respecting Enerplus Resources Fund -
Governance of Enerplus and the Management Agreement".

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, upon which the Trustee shall commence to wind up the affairs of the
Fund, provided that 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
shall 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 shall generally carry on no activities except
for the purpose of winding up the affairs of the Fund and, for this purpose, the
Trustee shall 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 such 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 currently 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. At Enerplus' annual general and
special meeting of unitholders to be held on April 25, 2002, unitholders will be
asked to pass an extraordinary resolution to amend the provisions of the Trust
Indenture to remove the uncertainty surrounding certain auditor-related matters
and provide the board of directors of EnerMark with more flexibility to deal
with the appointment of the Fund's auditors in the case of an auditors'
resignation or, in certain circumstances, removal.

                                      -26-
<PAGE>

Enerplus proposes to amend the Trust Indenture so that it will generally mirror
certain provisions of the BUSINESS CORPORATIONS ACT (Alberta) regarding the
appointment, removal and resignation of auditors. In particular, Enerplus
proposes that, if the Fund's auditors resign or are removed by the unitholders
without a successor properly appointed, the board of directors of EnerMark would
have the power to appoint new auditors to fill the vacancy created by the
resignation or removal. The new auditors would hold office until the next annual
meeting of the Fund's unitholders. The proposed amendments do not change the
basic concept that, in the absence of extraordinary events, the unitholders are
to appoint the Fund's auditors.

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
     INCOME TAX ACT (Canada);

(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.

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 income from their respective oil and natural gas properties
and operations. The Fund is entitled to be paid monthly the amount payable in
respect of such royalties on or about the 20th day of the second month following
the month to which such income relates. The income received by the Fund from
EnerMark and ERC is the gross production revenue from their oil and natural gas
operations, less certain permitted deductions (generally being operating costs,
general and administrative expenses, management fees, debt service charges,
taxes on the properties and site restoration and abandonment costs).

                                      -27-
<PAGE>

Unitholders may also receive distributions of the net proceeds received from the
sale of properties, although it is anticipated that such proceeds will generally
be used to repay debt or purchase additional properties and assets.

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. The royalty units are held by the Trustee
on behalf of the Fund.

GOVERNANCE OF ENERPLUS AND THE MANAGEMENT AGREEMENT

GENERAL

Pursuant to the Trust Indenture, the Trustee has delegated to the directors of
EnerMark the supervision of the business and affairs of the Fund, including the
supervision of EGEM in carrying out the duties delegated to it under the Trust
Indenture and the Management Agreement. Among other things, the board of
directors of EnerMark maintain responsibility for all matters relating to an
offering or repurchase of securities of the Fund or to a take-over bid or
similar transaction involving the Fund or its subsidiaries, the terms and
execution of material contracts on behalf of the Fund, the voting of securities
held by the Fund, the responsibility for borrowings and acquisitions by the Fund
and its subsidiaries and the approval of the public disclosure documents of the
Fund.

Pursuant to the Trust Indenture and in accordance with the Management Agreement,
EGEM has agreed to act as manager of the Fund and its subsidiaries. The Trustee
and the board of directors of EnerMark have retained EGEM to provide
comprehensive management services and have delegated certain authority to EGEM
to administer and regulate the day-to-day operations of the Fund and its
subsidiaries, subject to the supervision of the board of directors of EnerMark,
and to make executive decisions which conform to general policies and general
principles established by the board of directors of EnerMark. The EGEM officers
and employees who are involved in the management of the business and operations
of Enerplus perform essentially the same services as they would if they were
officers or employees of Enerplus. The officers provided by EGEM to Enerplus may
divide their time between the management of Enerplus and other management
obligations and interests, including those of affiliates of EGEM. See
"Management Agreement - Conflicts" below, "Risk Factors - Potential Conflicts of
Interest" and "Directors and Officers".

MANAGEMENT AGREEMENT

RESPONSIBILITIES

As discussed above, EGEM provides certain management, advisory and
administrative services to the Fund and its subsidiaries pursuant to the
Management Agreement. EGEM has been engaged by Enerplus to, among other things:

(a)  manage the business and affairs of EnerMark, ERC and any other subsidiary
     of the Fund, including the acquisition, exploration, development, operation
     (or the monitoring of third party operators) and disposition of oil and
     natural gas properties and assets and the marketing and dealing of the
     petroleum substances produced from such properties;

(b)  make available the office space, equipment and staff necessary for the
     proper administration and operation of Enerplus and its assets, including
     keeping necessary records and accounts relating to those operations;

(c)  arrange for, negotiate and administer all borrowings and credit facilities
     required by Enerplus (subject to the approval of the board of directors of
     EnerMark) and ensure compliance by Enerplus with applicable legal and
     disclosure obligations; and

(d)  manage and administer all matters relating to the Fund and the Trust Units,
     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) subject to the approval of the board of directors of EnerMark,
     calling, holding and distributing materials in respect of meetings of

                                      -28-
<PAGE>

     unitholders; and (v) subject to the approval of the board of directors of
     EnerMark, determining the timing and terms of future offerings, issuances
     and repurchases of Trust Units or other securities of the Fund.

Notwithstanding the above, the board of directors of EnerMark supervises the
management of the business and affairs of Enerplus generally and, without
limitation and in addition to those matters described under "Governance of
Enerplus and Management Agreement - General" above, the following matters
require the approval of the board of directors of EnerMark (or the relevant
operating subsidiary):

(a)  the acquisition and disposition of oil and natural gas properties, assets
     or entities for a purchase price in excess of $10,000,000 (or such greater
     amount as the board may determine);

(b)  the responsibility for approving capital expenditure and operational
     budgets of Enerplus; and

(c)  the yearly review of EGEM's performance under the Management Agreement and
     the extension of the term of the Management Agreement (as discussed below);
     and

(d)  the approval of any amendment to the constating documents and material
     contracts of the Fund on behalf of the Fund or its subsidiaries.

TERM

The Management Agreement is in effect for continuous three year terms. Upon the
approval of the board of directors of EnerMark prior to March 31 of each year,
each three year term will be extended for an additional year. As the term was
extended by the directors of EnerMark on March 7, 2002, the current term of the
Management Agreement continues to June 30, 2005.

COMPENSATION AND FEES

At the time of the Merger of Enerplus and EnerMark Income Fund on June 21, 2001,
the manner in which EGEM receives fees in consideration for its services
provided to Enerplus under the Management Agreement was significantly revised to
better align the interests of EGEM with the Fund's unitholders. Under the new
Management Agreement, base management fees are set at 2.75% of Enerplus' total
operating income (compared to pre-June 21, 2001 rates of 2.2% for EnerMark
Income Fund and 3.5% for Enerplus). In addition, acquisition and divestment fees
were eliminated and were replaced by performance fees based on both the total
return of the Fund, and its relative performance as compared to other senior oil
and gas trusts. The performance fees can range between 0% and 4% of the
operating income of Enerplus. In addition, EGEM is reimbursed for all general
and administrative costs incurred by it in performing its duties under the
Management Agreement. In connection with the merger, EGEM was guaranteed a
minimum performance fee of $5 million in 2001, which was capitalized as part of
the Merger cost.

As described above, there are two types of incremental performance fees which
can range, in the aggregate, from 0% to 4% of Enerplus' operating income for the
relevant period and which are based on the performance of the Fund in any
calendar year (and initially for the period from May 10, 2001 to December 31,
2001):

(a)  TOTAL RETURN PERFORMANCE FEE (minimum 0%, maximum 2% of the Fund's
     operating income).

     (i)  If the total return of the Trust Units in the period (i.e., the amount
          of distributions paid and appreciation in Trust Unit price) is less
          than the yield on 10-year Government of Canada bonds plus 5%, then no
          Total Return Performance Fee will be paid (subject to the minimum
          payment described in (iv) below).

     (ii) If the total return of the Trust Units in the period exceeds the yield
          on 10-year Government of Canada bonds plus 15%, then the Total Return
          Performance Fee will be 2% of the operating income of the Fund for
          that period.

                                      -29-
<PAGE>

    (iii) If the total return of the Trust Units is between the yield on
          10-year Government of Canada bonds plus a factor of 5% to 15%, then a
          sliding scale calculation, ranging from 0% to 2% of the operating
          income of the Fund (subject to the minimum payment described in (iv)
          below), will be used.

     (iv) Notwithstanding the above, if the total return of the Trust Units in
          the period exceeds 11%, then the Total Return Performance Fee will be
          a minimum of 0.5% of the Fund's operating income for the period.

(b)  RELATIVE PERFORMANCE FEE (minimum 0%, maximum 2% of the Fund's operating
     income).

     The relative performance of Enerplus as compared to eight other
     qualifying conventional oil and gas trusts in the relevant period will be
     ranked based on distributions paid and unit price appreciation in that
     period. The Relative Performance Fee will be calculated using a percentage
     equal to 2% divided by the number of trusts in the top half of the rankings
     which Enerplus is below the number one ranking, and subtracting the product
     obtained thereby from 2%. If the resulting value obtained is less than
     zero, then no Relative Performance Fee will be paid. Otherwise the Relative
     Performance Fee will be the amount obtained by multiplying the resulting
     percentage (not to exceed 2% of the Fund's operating income) by the
     operating income of the Fund. In effect, Enerplus must rank at least fourth
     out of the eight largest trusts (including Enerplus) before any Relative
     Performance Fee is payable.

The fee arrangements under the Management Agreement will be reviewed annually
with the board of directors of EnerMark.

The Management Fee is calculated at the end of each quarter or portion thereof
and paid on the last business day of the second month following such quarter.
The Total Return Performance Fee and the Relative Performance Fee are estimated
by EGEM and presented to the board of directors of EnerMark and paid on the last
business day of the second month following such quarter. Annually, EGEM presents
the board of directors with a final calculation of the actual Total Return
Performance Fee and Relative Performance Fee to be paid to EGEM in respect of
such period. EGEM then reconciles such amount to all quarterly payments of such
fees received by EGEM in respect of the applicable period and adjusts them
accordingly based on the reconciliation.

The Management Agreement also provides for the payment of certain fees to EGEM
in most instances of termination. See "Termination Provisions" below.

TERMINATION PROVISIONS

The Management Agreement may be terminated by the Fund, its subsidiaries or any
other entity managed by EGEM pursuant to the Management Agreement at any time
without the payment of compensation to EGEM if EGEM institutes bankruptcy
proceedings, seeks relief under bankruptcy law, consents to the appointment of a
receiver, voluntarily suspends transaction of its usual asset management
business, is declared bankrupt or insolvent, if a receiver is appointed in
respect of EGEM or if EGEM fails to carry out its material obligations under the
Management Agreement and does not cure such failure in accordance with the terms
of the Management Agreement.

The Management Agreement may be terminated pursuant to an extraordinary
resolution of Enerplus unitholders or, alternatively, by the board of directors
of EnerMark upon twelve months' notice to EGEM, in which cases the fees
described below shall be payable to EGEM. EGEM may terminate the Management
Agreement upon twelve months notice to Enerplus.

Notwithstanding the remaining term of the Management Agreement, if the agreement
is terminated pursuant to an extraordinary resolution of Enerplus unitholders,
in connection with the winding-up of the Fund, as a result of the Fund selling
all or all or substantially all of its assets or in any other manner which is
not permitted under the Management Agreement, and EGEM is not provided with a
twelve month notice period in respect of such termination, EGEM is entitled to
all fees and compensation owing to EGEM at the time of termination.

                                      -30-
<PAGE>

Additionally, EGEM is entitled to be reimbursed for all Termination Costs plus
an amount equal to either: (i) $40 million if the effective date of such
termination is prior to December 31, 2003; or (ii) the Termination Fees
multiplied by three.

Alternatively, the Management Agreement may be terminated by the board of
directors of EnerMark upon twelve months written notice to EGEM, during which
time EGEM shall continue to receive all fees and compensation pursuant to the
Management Agreement, followed by the payment of an amount equal to either: (i)
$40 million if the proposed effective date of such termination is on or prior to
December 31, 2003; or (ii) the Termination Fees multiplied by two, plus
reimbursement of all Termination Costs. The Management Agreement also provides
that any failure to annually extend such agreement shall be deemed to be a
termination thereof and that upon such an occurrence EGEM is entitled to receive
the aforementioned fees and compensation which would be payable to EGEM if the
Management Agreement were terminated with notice.

The Management Agreement also provides that, if any person announces a proposed
transaction which, if completed, would result in such person acquiring in excess
of 20% of the issued and outstanding Trust Units, acquiring all or substantially
all of the Fund's assets or would result in the winding-up or liquidating of the
Fund, or any similar transaction which in the reasonable opinion of EGEM might
result in the termination of the Management Agreement, then the Termination Fees
which would be payable to EGEM if the Management Agreement were terminated
without notice, plus the maximum allowable amount of Termination Costs which
would be payable to EGEM, shall be paid forthwith upon termination.

CONFLICTS

EGEM is one of the Enerplus Group of companies, which may manage other private
and public entities which are involved in the oil and natural gas business and
which may employ management, operational, exploitation and development
strategies similar to that employed by Enerplus. As a result, certain directors,
officers and employees of EGEM, and certain consultants retained by EGEM from
time to time, are also directors, officers and employees of affiliates of EGEM,
or may be consultants retained by affiliates of EGEM engaged in substantially
the same business. The Management Agreement contains provisions which require
EGEM to make disclosure to the board of directors of EnerMark of the fact and
substance of any particular conflict of interest in a matter which will treat
Enerplus, as the case may be, and the other interested party in an even handed
manner taking into account all of the circumstances of Enerplus, and such
interested party and to act honestly and in good faith in resolving such
matters. See "Risk Factors - Potential Conflicts of Interest" and "Directors and
Officers".

OTHER MATTERS

The Management Agreement may be assigned by any party only with 30 days prior
written notice and the prior written consent of the other parties, except that
EGEM can assign the agreement to an affiliate of EGEM (subject to the approval
of the EnerMark board of directors). The Management Agreement may only be
amended in writing by the parties thereto, provided that the Trustee shall act
in accordance with the direction of the board of directors of EnerMark with
respect to any proposed amendment. The Management Agreement contains provisions
which state that EGEM must act honestly, in good faith and with a view to the
best interests of Enerplus and its unitholders in carrying out its duties and
exercising its powers under the Management Agreement, and EGEM shall exercise
that degree of care, diligence and skill that a reasonably prudent advisor and
manager of petroleum and natural gas properties in western Canada would exercise
in comparable circumstances. Provided that EGEM acts in accordance with such
standard of care, EGEM is indemnified by Enerplus against any liabilities or
expenses it may incur in carrying out its duties and obligations under the
Management Agreement.

GOVERNANCE AGREEMENT

The Governance Agreement provides for certain matters respecting the governance
of Enerplus and its subsidiaries, including the right of EGEM to nominate three
members of the board of directors of EnerMark, which is to consist of a minimum
of seven and a maximum of eleven members, with the balance of the directors of
EnerMark to be nominated pursuant to a vote of the Fund's unitholders. The
unitholders will always be entitled to nominate a

                                      -31-
<PAGE>

majority of the EnerMark directors. Following the nomination of the directors by
the unitholders and EGEM, the Fund, as the sole shareholder of EnerMark, will
vote its shares to elect those nominees to the board of directors. The
Governance Agreement also states that the board of directors of ERC, which is a
wholly owned subsidiary of EnerMark, is to be comprised of the same persons as
the board of directors of EnerMark.

The Governance Agreement states, except where expressly prohibited in the Trust
Indenture and other material agreements of Enerplus, the Fund and EnerMark can
vote their shares of EnerMark and ERC, respectively. Under the Trust Indenture,
the ability to vote the EnerMark shares has been delegated, except in certain
circumstances, to the board of directors of EnerMark.

The Governance Agreement states, that the full amount of any dividends paid from
ERC to EnerMark must immediately be paid by EnerMark to the Fund.

Any person who subsequently becomes an owner of any shares of EnerMark or ERC
shall 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.

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. 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 at such
time. The Rights Plan is proposed to be renewed for another three years by the
Enerplus unitholders at the annual general and special meeting of unitholders to
be held on April 25, 2002.

                          DISTRIBUTIONS TO UNITHOLDERS

CASH DISTRIBUTION POLICY

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.

The following cash distributions were paid by each of Enerplus Resources Fund
and EnerMark Income Fund to their respective unitholders prior to the Merger.
The following amounts are stated before giving effect to the Merger and
therefore are not reflected on a combined basis.

                                      -32-
<PAGE>

<TABLE>
<CAPTION>
                                                              AMOUNT PER TRUST UNIT
------------------------------------------------------------------------------------------------------
            MONTH OF RECORD AND PAYMENT DATE     ENERPLUS RESOURCES FUND     ENERMARK INCOME FUND
------------------------------------------------------------------------------------------------------
     <S>                                         <C>                         <C>
     July, 2000                                           $0.30                      $0.06
     August, 2000                                          0.43                       0.09
     September, 2000                                       0.30                       0.06
     October, 2000                                         0.30                       0.06
     November, 2000                                        0.75                       0.12
     December, 2000                                        0.40                       0.08
     January, 2001(1)                                      0.40                       0.08
     February, 2001                                        0.65                       0.13
     March, 2001                                           0.45                       0.09
     April, 2001                                           0.45                       0.09
     May, 2001                                             0.90                       0.17
     June, 2001                                            0.52                       0.09
</TABLE>

The following cash distributions have been paid by Enerplus to its unitholders
following completion of the Merger.

<TABLE>
<CAPTION>
      MONTH OF RECORD AND
         PAYMENT DATE                          AMOUNT PER TRUST UNIT
-------------------------------------------------------------------------
     <S>                                       <C>
     July, 2001                                      $0.48
     August, 2001                                    $0.50
     September, 2001                                 $0.45
     October, 2001                                   $0.40
     November, 2001                                  $0.40
     December, 2001                                  $0.35
     January, 2002(1)                                $0.30
     February, 2002                                  $0.25
     March, 2002                                     $0.20
     April, 2002 (declared)                          $0.20
</TABLE>

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 INC. TAKING INTO ACCOUNT THE PREVAILING FINANCIAL
CIRCUMSTANCES OF THE FUND AT THE RELEVANT TIME. SEE "RISK FACTORS".

                               INDUSTRY CONDITIONS

CANADIAN GOVERNMENT REGULATION

The oil and natural gas industry is subject to extensive controls and
regulations imposed by various levels of government. It is not expected that any
of these controls or regulations will affect the operations of the Fund and ERC
in a manner materially different than they would affect other oil and natural
gas corporations of similar size.

PRICING AND MARKETING - OIL

In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. The
price depends in part on oil quality, prices of competing fuels, distance to
market, the value of refined products and the supply/demand balance. 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 ("NEB"). Any oil export to be made pursuant to a contract
of longer duration requires an exporter to obtain an export license from the NEB
and the issue of such a licence requires the approval of the Governor in
Council.

                                      -33-
<PAGE>

PRICING AND MARKETING - NATURAL GAS

In Canada the price of natural gas sold in intra-provincial, interprovincial and
international trade is determined by negotiation between buyers and sellers. The
price received by a natural gas producer depends, in part, on the price of
competing natural gas and other fuels, type of natural gas produced, access to
downstream transportation, length of contract term, weather conditions and the
supply/demand balance.

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, mainly in the case of removals exceeding two years, on such
factors as reserve availability, transportation arrangements, and market
considerations.

EXPORTS FROM CANADA

In order to export oil or natural gas from Canada, certain approvals are
required from the NEB and the Government of Canada. The approval(s) required are
dependent on the hydrocarbon substance being exported and the length of the
proposed export arrangement.

ROYALTIES AND INCENTIVES

In addition to federal regulation, each province has legislation and regulations
which govern land tenure, royalties, production rates, environmental protection
and other matters. The royalty regime is a significant factor in the
profitability of oil and natural gas production. Royalties payable on production
from lands other than Crown lands are determined by negotiations between the
mineral owner and the lessee. Crown royalties are determined by government
regulation and are generally calculated as a percentage of the value of the
gross production, and the rate of royalties payable generally depends in part on
prescribed reference prices, well productivity, geographical location, field
discovery date and the type or quality of the petroleum product produced.

From time to time the governments of Canada, Alberta, British Columbia and
Saskatchewan 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 Enerplus to the provincial governments.

CANADIAN 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
natural gas industry operations and can affect the location of wells and
facilities and the extent to which exploration and development is permitted. In
addition, legislation requires that well and facility sites be abandoned and
reclaimed to the satisfaction of provincial authorities. A breach of such
legislation may result in the imposition of fines and penalties, the suspension
or revocation of necessary licenses and authorizations, restrictions on the
transfer of well and facility sites and civil liability for pollution damage. In
Alberta, environmental compliance has been governed by the Alberta Environmental
Protection and Enhancement Act ("AEPEA") since September 1, 1993. In addition to
replacing a variety of older statutes which related to environmental matters,
the AEPEA also imposes certain new environmental compliance, reporting and
monitoring responsibilities and stricter environmental standards on oil and
natural gas operators in Alberta and in certain instances also imposes greater
fines and penalties for violations. As well, the AEPEA permits greater public
involvement in environmental assessment and enforcement.

                                      -34-
<PAGE>

                                  RISK FACTORS

The following are certain risk factors relating to the business of Enerplus
which prospective investors should carefully consider before deciding whether to
purchase Trust Units. The following information is a summary only of certain
risk factors and is qualified in its entirety by reference to, and must be read
in conjunction with, the detailed information appearing elsewhere in this
Renewal Annual Information Form.

LIMITED PURPOSE TRUST

The Fund is a limited purpose trust which is entirely dependent upon the
operations and assets of its subsidiaries through the Fund's ownership of the
securities of, and royalties and debt instruments issued by, those subsidiaries.
Enerplus' income will be received from the production of crude oil and natural
gas from its resource properties and will be susceptible to the risks and
uncertainties associated with the oil and natural gas industry generally. Since
the primary focus is to pursue growth opportunities through the development of
existing reserves and acquisition of new properties, Enerplus' involvement in
the exploration for oil and natural gas is minimal. As a result, if the oil and
natural gas reserves associated with Enerplus' resource properties are not
supplemented through additional development or the acquisition of additional oil
and natural gas properties, the ability of Enerplus to continue to generate cash
flow for distribution to unitholders may be adversely affected.

EXPLOITATION AND DEVELOPMENT

Exploitation and development risks arise due to the uncertain results of
searching for and producing oil and natural gas using imperfect scientific
methods. These 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 will be used by Enerplus to improve
its ability to find, develop and produce oil and natural gas.

OPERATIONS

Enerplus' operations are subject to all of the risks normally incident to the
operation and development of oil and natural gas properties and the drilling of
oil and natural gas wells, including encountering unexpected formations or
pressures, blow-outs, craterings and fires, all of which could result in
personal injuries, loss of life and damage to property of Enerplus and others.
Enerplus has both safety and environmental policies in place to protect its
operators and employees, as well as to meet the regulatory requirements in those
areas where they operate. In addition, Enerplus has liability insurance policies
in place in such amounts as it considers adequate, however, it will not be fully
insured against all of these risks, nor are all such risks insurable. Business
interruption insurance may also be purchased for selected facilities, to the
extent that such insurance is available. Enerplus may become liable for damages
arising from such events against which it cannot insure or against which it may
elect not to insure because of high premium costs or other reasons. Costs
incurred to repair such damage or pay such liabilities will reduce payments made
by the operating subsidiaries to the Fund.

Continuing production from a property, and to some extent the marketing of
production therefrom, are largely dependent upon the ability of the operator of
the property. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although satisfactory
title reviews are to be conducted in accordance with industry standards, such
reviews do not guarantee or certify that a defect in the chain of title may not
arise to defeat the claim of Enerplus to certain properties. A reduction of the
payments made by the operating subsidiaries to the Fund could result in such
circumstances.

OIL AND NATURAL GAS PRICES

Enerplus' results of operations and financial condition, and therefore the
amounts paid to the Fund by its subsidiaries, are dependent on the prices
received for their oil and natural gas production. Oil and natural gas prices
have

                                      -35-
<PAGE>

fluctuated widely during recent years and are determined by supply and
demand factors, including weather and general economic conditions as well as
conditions in other oil producing regions, which are beyond the control of
Enerplus. Any decline in oil and natural gas prices could have a material
adverse effect on Enerplus' operations, financial condition, the value of their
reserves and the level of expenditures for the development of its oil and
natural gas reserves. World oil prices are quoted in United States dollars and
the price received by Canadian producers is therefore affected by the
Canadian/U.S. dollar exchange rate that may fluctuate over time. A material
increase in the value of the Canadian dollar may negatively impact Enerplus' net
production revenue. Enerplus and EGEM may manage the risk associated with
changes in commodity prices and foreign exchanges rates by causing Enerplus to,
from time to time, enter into oil or natural gas price hedges and forward
foreign exchange contracts. To the extent that Enerplus engages in risk
management activities related to commodity prices and foreign exchange rates, it
will be subject to credit risks associated with counterparties with which it
contracts.

CAPITAL INVESTMENT

The timing and amount of capital expenditures will directly affect the amount of
income for distribution to unitholders. Distributions may be reduced, or even
eliminated, at times when significant capital or other expenditures are made. To
the extent that external sources of capital, including the issuance of
additional Trust Units, become limited or unavailable, Enerplus' ability to make
the necessary capital investments to maintain or expand their 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.

DEBT SERVICE

Enerplus has unsecured credit facilities. Variations in interest rates and
scheduled principal repayments, if required under the terms of the 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 the agreements with the lenders
may also limit payments by the operating subsidiaries to the Fund. Although it
is believed that the bank lines of credit are 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.

If Enerplus becomes unable to pay its debt service charges or otherwise commits
an event of default, such as bankruptcy, the lenders may rank senior to
securities or royalties of the operating subsidiaries which are held by the
Fund.

DELAY IN CASH DISTRIBUTIONS

In addition to the usual delays in payment by purchasers of oil and natural gas
to the operators of Enerplus' properties, and by the operator to Enerplus,
payments between any of such parties may also be delayed by restrictions imposed
by lenders, delays in the sale or delivery of products, delays in the connection
of wells to a gathering system, blowouts or other accidents, recovery by the
operator of expenses incurred in the operation of the properties or the
establishment by the operator of reserves for such expenses.

RESERVES

Although Sproule and EGEM have prepared Enerplus' reserve figures using methods
of estimating reserves consistent with those commonly followed in the industry
and believe that those methods have been verified by operating experience, such
figures are estimates and no assurance can be given that the indicated levels of
reserves will be produced. Probable reserves estimated for properties may
require revision based on the actual development strategies employed to prove
such reserves. Estimated reserves may also be affected by changes in oil and
natural gas prices. Declines in Enerplus' reserves which are not offset by the
acquisition or development of additional reserves may reduce the underlying
value of Trust Units to unitholders.

                                      -36-
<PAGE>

The reserve reports under the heading "Oil and Natural Gas Reserves" have been
prepared using certain commodity price assumptions which are described in the
notes to the reserve tables. If lower prices for crude oil, NGLs and natural gas
are realized by Enerplus and substituted for the prices assumptions utilized in
those reserve reports, the present value of estimated future net cash flows for
Enerplus' reserves would be reduced and the reduction could be significant,
particularly based on the constant price case assumptions.

INVESTMENT ELIGIBILITY

If Enerplus ceases to qualify as a mutual fund trust, the Trust Units will cease
to be qualified investments for RRSPs, RRIFs, RESPs and DPSPs (collectively,
"Exempt Plans"). Where at the end of any month an Exempt Plan holds Trust Units
that are not qualified investments, the Exempt Plan must, in respect of that
month, pay a tax under Part XI.1 of the INCOME TAX ACT (Canada) equal to 1% of
the fair market value of the Trust Units at the time those Trust Units were
acquired by the Exempt Plan. In addition, where a trust governed by an RRSP or
RRIF holds Trust Units that are not qualified investments, the trust will become
taxable on its income attributable to the Trust Units while they are not
qualified investments. RESPs which hold Trust Units that are not qualified
investments may have their registration revoked by the Canada Customs and
Revenue Agency.

If Enerplus ceases to qualify as a mutual fund trust, it will be required to pay
a tax under Part XII.2 of the INCOME TAX ACT (Canada). The payment of Part XII.2
tax by Enerplus may have adverse income tax consequences for certain unitholders
including non-resident persons and Exempt Plans that acquire an interest in
Enerplus directly or indirectly from another unitholder.

ENVIRONMENTAL CONCERNS

The oil and natural gas industry is subject to environmental regulation pursuant
to local, provincial and federal legislation. A breach of such legislation may
result in the imposition of fines or issuance of clean up orders in respect of
Enerplus or its properties. Such legislation may be changed to impose higher
standards and potentially more costly obligations on Enerplus, and there can be
no assurance that Enerplus will be able to satisfy its actual future
environmental and reclamation obligations. Additionally, the potential impact on
Enerplus' operations and business of the December 1997 Kyoto treaty with respect
to instituting reductions of greenhouse gases is difficult to quantify at this
time as specific measures for meeting Canada's commitments have not been
developed and the treaty itself may be modified or nullified.

Actual site reclamation or abandonment costs incurred in the ordinary course in
a specific period are deducted for purposes of calculating income paid to the
Fund by its subsidiaries and will reduce the amount of distributable income
available for distribution to unitholders.

RELIANCE ON MANAGEMENT

Unitholders will be dependent on the management of Enerplus and EGEM in respect
of the administration and management of all matters relating to Enerplus and its
operations and administration. The loss of the services of key individuals or
termination of the Management Agreement could have a detrimental effect on
Enerplus. Enerplus currently operates approximately 65% of its total daily
production. Investors who are not willing to rely on the management of Enerplus
and EGEM should not invest in the Trust Units.

DEPLETION OF RESERVES

Enerplus has certain unique attributes which differentiate it from other oil and
gas industry participants. Distributions of income from crude oil and natural
gas production, absent commodity price increases or cost effective acquisition
and development activities, will decline over time in a manner consistent with
declining production from typical oil, natural gas and natural gas liquids
reserves. Enerplus will not be reinvesting cash flow in the same manner as other
industry participants. Accordingly, absent capital injections, Enerplus' initial
production levels and reserves will decline.

                                      -37-
<PAGE>

The future oil and natural gas reserves and production of Enerplus, and
therefore its cash flows, will be highly dependent on its success in exploiting
its reserve base and acquiring additional reserves. Without reserve additions
through acquisition or development activities, Enerplus' reserves and production
will decline over time as reserves are exploited.

To the extent that external sources of capital, including the issuance of
additional Trust Units, become limited or unavailable, the ability of Enerplus
to make the necessary capital investments to maintain or expand its oil and
natural gas reserves will be impaired. To the extent that Enerplus is required
to use cash flow to finance capital expenditures or property acquisitions, the
level of distributable income will be reduced.

There can be no assurance that Enerplus and EGEM will be successful in
developing or acquiring additional reserves on terms that meet Enerplus'
investment objectives.

ADDITIONAL FINANCING

To the extent that external sources of capital, including the issuance of
additional Trust Units, become limited or unavailable, Enerplus' ability to make
the necessary capital investments to maintain or expand its oil and gas reserves
will be impaired. To the extent that Enerplus is required to use cash flow to
finance capital expenditures or property acquisitions, the level of
distributable income will be reduced.

COMPETITION

There is strong competition relating to all aspects of the oil and gas industry.
Enerplus and EGEM will actively compete for capital, skilled personnel,
undeveloped lands, reserves acquisitions, access to drilling rigs, service rigs
and other equipment, access to processing facilities and pipeline and refining
capacity and in all other aspects of its operations with a substantial number of
other organizations, many of which may have greater technical and financial
resources than Enerplus and EGEM. Some of those organizations not only explore
for, develop and produce oil and natural gas but also carry on refining
operations and market petroleum and other products on a world wide basis and as
such have greater and more diverse resources on which to draw.

RETURN OF CAPITAL

Trust Units will have no value when reserves from Enerplus' properties can no
longer be economically produced or marketed and, as a result, cash distributions
do not represent a "yield" in the traditional sense as they represent both
return of capital and return on investment. Unitholders will have to obtain the
return of capital invested out of cash flow derived from their investments in
the Trust Units during the period when reserves can be economically recovered.

POTENTIAL CONFLICTS OF INTEREST

There may be circumstances in which the interests of EGEM, its affiliates or
entities managed by them will conflict with those of Enerplus and its
unitholders. EGEM or its affiliates may acquire oil and gas properties or
entities on its own behalf or on behalf of persons other than Enerplus and may
manage and administer those additional properties or entities, as well as enter
into other types of energy-related management, advisory and investment
activities. Neither EGEM, nor its management or affiliates, carry on their
full-time activities on behalf of Enerplus and, when acting on their own behalf
or on behalf of others, may at times act in competition with the interests of
Enerplus and its unitholders.

In the event of such conflicts, decisions will be made on a basis consistent
with the objectives and financial resources of each group of interested parties,
the time limitations on investment of such financial resources, and on the basis
of operating efficiencies having regard to the then current holdings of
properties of each group of interested parties consistent with the duties of
EGEM to each such group of persons. EGEM will use all reasonable efforts to
resolve such conflicts of interest in a manner which will treat Enerplus and the
other interested party fairly taking into

                                      -38-
<PAGE>

account all of the circumstances of Enerplus and such interested party and to
act honestly and in good faith in resolving such matters.

Circumstances may also arise where members of the board of directors of EnerMark
or EGEM 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 board members
will be provided to Enerplus.

NATURE OF TRUST UNITS

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'
operating subsidiaries. The Trust Units are also dissimilar to conventional debt
instruments in that there is no principal amount owing directly to unitholders.
The Trust Units represent a fractional interest in the Fund. As holders of Trust
Units, unitholders will not have the statutory rights normally associated with
ownership of shares of a corporation including, for example, the right to bring
"oppression" or "derivative" actions. The Fund's assets are the shares of,
royalties granted by, and certain unsecured debt instruments of its operating
subsidiaries, and may also include certain other investments permitted under the
Trust Indenture. The price per Trust Unit is a function of anticipated
distributable income, the oil and natural gas properties acquired by Enerplus
and the ability to effect long-term growth in the value of Enerplus. The market
price of the Trust Units will be sensitive to a variety of market conditions
including, but not limited to, interest rates and the ability of Enerplus to
acquire suitable oil and natural gas properties. Changes in market conditions
may adversely affect the trading price of the Trust Units.

UNITHOLDER LIMITED LIABILITY

The Trust Indenture provides that no unitholder will be subject to any personal
liability in connection with the Fund or its obligations and affairs, and the
satisfaction of claims of any nature arising out of or in connection therewith
is only to be made out of the Fund's assets. Additionally, the Trust Indenture
states that no unitholder is liable to indemnify or reimburse the Trustee for
any liabilities incurred by the Trustee with respect to any taxes payable by or
liabilities incurred by the Fund or the Trustee, and all such liabilities will
be enforceable only against, and will be satisfied only out of, the Fund's
assets. Notwithstanding the foregoing statements in the Trust Indenture, because
of uncertainties in the law relating to investment trusts such as the Fund,
there is a risk that a unitholder could be held personally liable for
obligations of the Fund to the extent that claims are not satisfied by the Fund.
It is intended that the operations of the Fund will be conducted, upon the
advice of counsel, in such a way and in such jurisdictions as to avoid as far as
possible any material risk of liability on the unitholders for claims against
the Fund. In any event, it is considered that the risk of any personal liability
of unitholders in Canada is minimal, particularly 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 Enerplus and its
unitholders.

CHANGES IN LEGISLATION

There can be no assurances that income tax laws and government incentive
programs relating to the oil and gas industry, such as the status of mutual fund
trusts and the resource allowance, will not be changed in a manner which
adversely affects Enerplus and its unitholders. There can be no assurance that
the Canada Customs and Revenue Agency or the Internal Revenue Service will agree
with how Enerplus calculates its income for tax purposes or that the Canada
Customs and Revenue Agency or the Internal Revenue Service will not change their
administrative practices to the detriment of Enerplus or its unitholders.

RETRACTION RIGHT

It is anticipated that the retraction right will not be the primary mechanism
for unitholders to liquidate their investment. Cash distributions are subject to
limitations and any securities which may be distributed in specie to unitholders
in connection with a retraction will not be listed on any stock exchange and no
market is expected to

                                      -39-
<PAGE>

develop for such securities. In addition, there may be resale restrictions
imposed by law upon the recipients of the securities pursuant to the retraction
right.

                   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

<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31,
                                                      -----------------------------------------------------
($THOUSANDS, EXCEPT PER TRUST UNIT AMOUNTS)                 2001               2000               1999
                                                      ---------------    ---------------    ---------------
<S>                                                      <C>               <C>                <C>
FINANCIAL
Gross oil and gas sales                                  $  639,397        $  343,182          $169,541
Funds flow from operations                                  340,246           176,366            80,965
   Per Trust Unit                                              6.20              6.57              3.94
Net income                                                  180,269            82,150            25,754
   Per Trust Unit - Basic                                      3.28              3.06              1.25
   Per Trust Unit - Diluted                                    3.28              3.05              1.25
Capital expenditures (net)                                  152,216            65,844            12,136
Total assets                                              2,284,253         1,567,952           576,901
Long term debt                                              412,589           275,944           131,315

CASH AVAILABLE FOR DISTRIBUTION
  Funds flow from operations                                340,246           176,366            80,965
  Site restoration and abandonment costs incurred             2,628             1,471             1,124
  Cash withheld for debt reduction                          (48,850)          (11,746)           (3,900)
  Enerplus Resources Fund (pre-Merger) cash flows            16,870                 -                 -
  Accruals                                                    5,560                 -                 -
  Pursuit Resources Corp. operating cash flows net
     of cash withheld for debt reduction                          -             2,090                 -
                                                      ---------------    ---------------    ---------------
Cash available for distribution                          $  316,454        $  168,181          $ 78,189
                                                      ---------------    ---------------    ---------------
                                                      ---------------    ---------------    ---------------
Per Trust Unit                                           $     5.67        $     5.49          $   3.70
                                                      ---------------    ---------------    ---------------
                                                      ---------------    ---------------    ---------------
</TABLE>

The above financial data has been taken from the audited consolidated financial
statements of Enerplus for the years ended December 31, 2001, 2000 and 1999. The
audited consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles. See Note 2 to Enerplus'
audited annual consolidated financial statements of the year ended December 31,
2001 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 OF FINANCIAL CONDITION
                          AND RESULTS OF OPERATIONS

Management's discussion and analysis of financial condition and results of
operations for the year ended December 31, 2001, as contained on pages 33 to 50
of the Fund's Annual Report for the year ended December 31, 2001, is
incorporated by reference in this Renewal Annual Information Form.

                                      -40-
<PAGE>

                              MARKET FOR SECURITIES

The Trust Units are listed and posted for trading on The Toronto Stock Exchange
and the New York Stock Exchange. The trading symbol for the Trust Units on the
TSE is "ERF.UN" and on the NYSE is "ERF".

                             DIRECTORS AND OFFICERS

DIRECTORS OF ENERMARK

With the exception of three directors of EnerMark who, pursuant to the
Governance Agreement, are nominated by EGEM, the directors of EnerMark are
nominated by the unitholders of the Fund at each annual meeting of unitholders.
All directors serve until the next annual meeting or until a successor is
elected or appointed. See "Governance Agreement". 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:

<TABLE>
<CAPTION>

     NAME AND MUNICIPALITY
          OF RESIDENCE            DIRECTOR SINCE                PRINCIPAL OCCUPATION FOR PAST FIVE YEARS

------------------------------- ------------------- -----------------------------------------------------------------------
<S>                               <C>               <C>
Andre Bineau (2)                  February, 1996    Vice President ofAssociation de bienfaisance et de retraite des
Montreal, Quebec                                    policiers et policieres de la Ville de Montreal (a municipal pension plan)

Derek J.M. Fortune(4)(5)(6)         June, 2001      Secretary/Manager, City of Ottawa Superannuation Fund (a
Ottawa, Ontario                                     municipal pension plan)

Gordon J. Kerr(5)(7)(10)             May, 2001      President and Chief Executive Officer of EGEM since May, 2001
Calgary, Alberta                                    (and Chief Financial Officer of EGEM until December 2001). Executive
                                                    Vice President and Chief Financial Officer of EGEM since January,
                                                    2001. Prior thereto, Senior Vice President, Financial Services of EGEM
                                                    since September, 2000. Prior thereto, Vice President, Finance and
                                                    Chief Financial Officer of EGEM since 1998. Prior thereto, Strategic
                                                    Development Consultant to EGEM since 1996.

Douglas R. Martin(1)(4)(5)(8)       July, 2000      President of Charles Avenue Capital Corp. (a private merchant
Calgary, Alberta                                    banking company) since April, 2000.  Prior thereto, Chairman of
                                                    the Board of Pursuit Resources Corp. (an oil and natural gas
                                                    exploration and production company)

Arne Nielsen(3)(6)                  June, 2001      Chairman of Shiningbank Energy Management Inc. (manager of an
Calgary, Alberta                                    energy investment trust)

Robert Normand(2)(4)(6)             June, 2001      Businessman
Montreal, Quebec

Eric P. Tremblay(3)(7)(10)        January, 2001     Senior Vice President, Capital Markets of EGEM since September,
Calgary, Alberta                                    2000.  Prior thereto, Senior Vice President, Corporate Development of
                                                    EGEM since January, 2000. Prior thereto, Vice President, Corporate
                                                    Development of EGEM since 1996.

Harry B. Wheeler(2)(3)            January, 2001     President of Colchester Investments Ltd. (a private investment
Calgary, Alberta                                    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(7)(9)            January, 2001     Managing Director of EnCap Investments L.L.C. (a wholly owned
Houston, Texas                                      subsidiary of El Paso Corporation, which provides private
                                                    equity financing to the oil and gas industry)
</TABLE>

                                      -41-
<PAGE>

NOTES:

(1)  Chairman of the Board of Directors.

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

(3)  The Environment, Safety and Reserves Committee is comprised of Harry B.
     Wheeler as Chairman, Arne Nielsen and Eric P. Tremblay.

(4)  The Corporate Governance Committee is comprised of Douglas R. Martin as
     Chairman, Robert Normand and Derek J. M. Fortune.

(5)  The Compensation and Human Resources Committee is comprised of Derek J. M.
     Fortune as Chairman, Douglas R. Martin and Gordon J. Kerr.

(6)  Prior to the merger of Enerplus and EnerMark Income Fund on June 21, 2001,
     each of Derek J.M. Fortune, Arne Nielsen 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, Mr. Nielsen was a director of ERC since June, 2000
     and Mr. Normand was a director of ERC since March, 1998.

(7) Nominee of EGEM pursuant to the Management Agreement

(8)  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.

(9)  In late 1997, Mr. Zorich was appointed to the board of directors of Benz
     Energy Inc. ("Benz"), a Vancouver Stock 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.

(10) Prior to June 21, 2001, EGEM's role as the principal management company of
     Enerplus Resources Fund was performed by Enerplus Energy Services Ltd.
     ("EES"), a private company which was owned by EGEM. All references to EGEM
     in the above table prior to June 21, 2001 should be construed as references
     to EES, but for simplicity, EGEM has been utilized throughout the above
     table.

OFFICERS OF ENERMARK AND EGEM

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

<TABLE>
<CAPTION>
 NAME AND MUNICIPALITY       POSITION WITH
      OF RESIDENCE             ENERMARK            POSITION WITH EGEM     PRINCIPAL OCCUPATION FOR PAST FIVE YEARS(1)
-----------------------   --------------------   ----------------------   --------------------------------------------------------
<S>                       <C>                    <C>                      <C>
Gordon J. Kerr            President and Chief    President and Chief      President and Chief Executive Officer of
Calgary, Alberta          Executive Officer      Executive Officer        EGEM since May, 2001 (and Chief Financial
                                                                          Officer of EGEM until December 2001). Prior thereto,
                                                                          Executive Vice President and Chief Financial Officer
                                                                          of EGEM since January, 2001. Prior thereto, Senior
                                                                          Vice President, Financial Services of EGEM since
                                                                          September, 2000. Prior thereto, Vice President,
                                                                          Finance and Chief Financial Officer of EGEM since 1998.
                                                                          Prior thereto, Strategic Development Consultant to
                                                                          EGEM since 1996.

Heather J. Culbert        Senior Vice            Senior Vice President,   Senior Vice President, Corporate Services
Calgary, Alberta          President, Corporate   Corporate Services       of EGEM since March 2001.  Prior thereto,
                          Services                                        Vice President, Management Information
                                                                          Systems & Administration of EGEM since 1996.
</TABLE>

                                      -42-
<PAGE>

<TABLE>
<CAPTION>

 NAME AND MUNICIPALITY       POSITION WITH
      OF RESIDENCE             ENERMARK            POSITION WITH EGEM     PRINCIPAL OCCUPATION FOR PAST FIVE YEARS(1)
-----------------------   --------------------   ----------------------   --------------------------------------------------------
<S>                       <C>                    <C>                      <C>
Garry A. Tanner           N/A                    Senior Vice President,   Senior Vice President, New Business
Calgary, Alberta                                 New Business             Development of EGEM since August, 2001
                                                 Development              (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          Senior Vice            Senior Vice President,   Senior Vice President, Capital Markets of
Calgary, Alberta          President, Capital     Capital Markets          EGEM since September, 2000.  Prior
                          Markets                                         thereto, Senior Vice President, Corporate
                                                                          Development of EGEM  since January,
                                                                          2000.  Prior thereto, Vice President,
                                                                          Corporate Development of EGEM since 1996.

Robert J. Waters          Senior Vice            Senior Vice President    Senior Vice President and Chief Financial
Calgary, Alberta          President and Chief    and Chief Financial      Officer of EGEM since December, 2001.
                          Financial Officer      Officer                  Prior thereto, Vice President, Finance and Chief
                                                                          Financial Officer of Pengrowth Corporation since
                                                                          June, 1998. Prior thereto, Treasurer of Norcen Energy
                                                                          Resources Limited (an oil and gas exploration and
                                                                          production company) since 1988.

Jo-Anne M. Caza           Vice President,        N/A                      Vice President of Investor Relations of
Calgary, Alberta          Investor Relations                              Enerplus since January, 2000. Prior
                                                                          thereto, Manager, Investor Relations of
                                                                          Enerplus since 1998.  Prior thereto,
                                                                          Investor Relations Supervisor of Enerplus
                                                                          since 1996.

Daryl W. Cook             Vice President,        N/A                      Vice President, Operations of Enerplus
Calgary, Alberta          Operations                                      since 1997.  Prior thereto, Vice President,
                                                                          Exploitation and Land of Enerplus.

Dorothy J. Else           Vice President, Land   N/A                      Vice President, Land of Enerplus since
Calgary, Alberta                                                          1998.  Prior thereto, Manager of Land of Enerplus.

Wayne T. Foch             Vice President,        N/A                      Vice President, Finance of Enerplus since
Calgary, Alberta          Finance                                         February, 2001.  Prior thereto, Treasurer
                                                                          of EMR Resource Management Ltd. (the
                                                                          management company of EnerMark Income
                                                                          Fund) since April, 1996.

I. Laura Pierrot          Vice President and     N/A                      Vice President and Treasurer of Enerplus
Calgary, Alberta          Treasurer                                       since February, 2001.  Prior thereto,
                                                                          Treasurer of Enerplus.

Darrell Shaw              Vice President,        N/A                      Vice President, Exploitation of Enerplus
Calgary, Alberta          Exploitation                                    since 1998.  Prior thereto, General
                                                                          Manager, Exploitation of Enerplus.
</TABLE>

                                      -43-
<PAGE>

<TABLE>
<CAPTION>

 NAME AND MUNICIPALITY       POSITION WITH
      OF RESIDENCE             ENERMARK            POSITION WITH EGEM     PRINCIPAL OCCUPATION FOR PAST FIVE YEARS(1)
-----------------------   --------------------   ----------------------   --------------------------------------------------------
<S>                       <C>                    <C>                      <C>
Gerald F. Stevenson       Vice President,        N/A                      Vice President, Acquisitions of Enerplus
Calgary, Alberta          Acquisitions                                    since October, 2001.  Prior thereto,
                                                                          consultant with Waterous & Co. (a
                                                                          financial advisory firm to the oil and
                                                                          gas industry) since February, 2000.
                                                                          Prior thereto, advisor to Hurricane
                                                                          Hydrocarbons Ltd. ("HHC") (an oil and gas
                                                                          exploration and production company) from
                                                                          April, 1999 to December, 1999.  Prior
                                                                          thereto, Interim President and Chief
                                                                          Executive Officer of HHC from October,
                                                                          1998.  Prior thereto, Vice President
                                                                          Production of HHC from April, 1998.
                                                                          Prior thereto, a consultant to Mercantile
                                                                          Latin America an oil and gas company)
                                                                          from September, 1997 to February, 1998.
                                                                          Prior thereto, Associate with Waterous &
                                                                          Co. since July, 1993.

Wayne Ford                Controller             N/A                      Controller of Enerplus since August,
Calgary, Alberta                                                          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.

Ian Dundas                N/A                    Vice President           Vice President, EGEM since August, 2001.
Calgary, Alberta                                                          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.

Larry Titley              N/A                    Treasurer                Treasurer of EGEM since January, 1998.
Calgary, Alberta                                                          Prior thereto, Manager of Financial Reporting and
                                                                          Accounting of EGEM since June, 1996.

Christina S. Meeuwsen     Corporate Secretary    Corporate Secretary      Corporate Secretary of EGEM since 1996.
Calgary, Alberta

Joanne Danyschuk          Assistant Corporate    Assistant Corporate      Assistant Corporate Secretary of EGEM
Calgary, Alberta          Secretary              Secretary                since 1997.  Prior thereto, Corporate Law Clerk
                                                                          at Blake, Cassels &  LLP (law firm).
</TABLE>

NOTE:

(1)  Those persons whose principal occupations are designated as officers of
     Enerplus are not officers of EGEM but are only officers of EnerMark.
     However, prior to June 21, 2001, EGEM's role as the principal management
     company of Enerplus Resources Fund was performed by Enerplus Energy
     Services Ltd. ("EES"), a private company which was owned by EGEM, and the
     principal employer of such persons prior to such time was EES. Therefore,
     all references to EGEM or to Enerplus (with respect to those officers who
     are not officers of EGEM) prior to June 21, 2001 should be construed as
     references to EES, but for simplicity, EGEM and Enerplus, as applicable,
     have been utilized throughout the above table.

The directors and officers named above beneficially own, directly or indirectly,
an aggregate of 462,427 Trust Units, representing approximately 0.66% of the
Trust Units outstanding on March 31, 2002.

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 "Management Agreement - Conflicts" and "Risk Factors - Potential
Conflicts of Interest".

                                      -44-
<Page>

                             ADDITIONAL INFORMATION

Enerplus will provide to any person, upon request to the Corporate Secretary
of EGEM:

(a)  when the securities of Enerplus 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 Enerplus' 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 Enerplus
          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 Enerplus 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 security holder of Enerplus.

Additional information regarding directors' and certain officers' remuneration
and indebtedness, remuneration of EGEM pursuant to the Management Agreement,
principal holders of Trust Units, options to purchase Trust Units and interests
of insiders in material transactions is contained in Enerplus' 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, 2001.

                                      -45-
<PAGE>

                                  APPENDIX "A"

              UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

                               COMPILATION REPORT

TO:      The Directors of EnerMark Inc.

         We have reviewed, as to compilation only, the accompanying unaudited
pro forma consolidated statements of income and cash available for distribution
of Enerplus Resources Fund (the "Fund") for the year ended December 31, 2001.
These pro forma consolidated financial statements have been prepared for
inclusion in the Renewal Annual Information Form of the Fund dated April 10,
2002. In our opinion, the unaudited pro forma consolidated statements of income
and cash available for distribution have been properly compiled to give effect
to the proposed transaction and the assumptions described in the notes thereto.

Calgary, Alberta                                 "ARTHUR ANDERSEN LLP"
April 10, 2002.                                  Chartered Accountants

                                      A-1
<PAGE>

                             ENERPLUS RESOURCES FUND
                   PRO FORMA CONSOLIDATED STATEMENT OF INCOME
                      FOR THE YEAR ENDED DECEMBER 31, 2001
                                   (UNAUDITED)

<TABLE>
<CAPTION>
($ thousands except per Trust Unit amounts)
                                                                    ENERPLUS
                                                                (PRE-ACQUISITION)                      PRO FORMA
                                                  ENERPLUS          171 DAYS         ADJUSTMENTS     CONSOLIDATED
                                                -------------   -----------------   -------------   ---------------
<S>                                               <C>           <C>                  <C>             <C>
REVENUES
    Oil and gas sales.........................    $ 639,379         $122,343           $     -          $ 761,722
    Crown royalties...........................     (101,114)         (18,951)             (236) (2a)     (120,301)
    Freehold and other royalties..............      (31,546)          (7,149)              682  (2c)      (38,013)
                                                -------------   -----------------    -----------     --------------
                                                    506,719           96,243               446            603,408
    Interest and other income.................          858              177                 -              1,035
                                                -------------   -----------------    -----------     --------------
                                                    507,577           96,420               446            604,443
                                                -------------   -----------------    -----------     --------------
EXPENSES
    Operating.................................      120,082           18,136                 -            138,218
    General and administrative................       12,971            1,969                 -             14,940
    Management fee............................        9,323            2,743               412  (2b)       12,478
    Interest..................................       17,605            2,717                 -             20,322
    Depletion, depreciation and amortization..      194,080           15,441             8,336  (2d)      217,857
                                                -------------   -----------------    -----------     --------------
                                                    354,061           41,006             8,748            403,815
                                                -------------   -----------------    -----------     --------------
INCOME BEFORE TAXES.........................        153,516           55,414            (8,302)           200,628
                                                -------------   -----------------    -----------     --------------
    Capital taxes.............................        4,722              526                 -              5,248
    Future income tax provision (recovery)....      (31,475)             274                 -            (31,201)
                                                -------------   -----------------    -----------     --------------
NET INCOME................................        $ 180,269         $ 54,614           $(8,302)         $ 226,581
                                                -------------   -----------------    -----------     --------------
                                                -------------   -----------------    -----------     --------------
NET INCOME PER TRUST UNIT

    Basic.....................................        $3.28                                                 $3.50
                                                -------------                                        --------------
                                                -------------                                        --------------
    Diluted...................................        $3.28                                                 $3.50
                                                -------------                                        --------------
                                                -------------                                        --------------
</TABLE>

                                      A-2
<PAGE>

                             ENERPLUS RESOURCES FUND
       PRO FORMA CONSOLIDATED STATEMENT OF CASH AVAILABLE FOR DISTRIBUTION
                      FOR THE YEAR ENDED DECEMBER 31, 2001
                                   (UNAUDITED)

($ thousands except per Trust Unit amounts)
<TABLE>
<CAPTION>
                                                                       ENERPLUS
                                                                   (PRE-ACQUISITION)                      PRO FORMA
                                                     ENERPLUS          171 DAYS         ADJUSTMENTS     CONSOLIDATED
                                                   -------------   -----------------   -------------   ---------------
<S>                                                  <C>           <C>                  <C>             <C>
Net income......................................      $180,269         $54,614            $(8,302)         $226,581
Depletion, depreciation and amortization........       194,080          15,441              8,336           217,857
Future income tax provision (recovery)..........       (31,475)            274                  -           (31,201)
Site restoration and abandonment costs incurred.        (2,628)           (633)                 -            (3,261)
                                                   -------------   -----------------    -----------     --------------
Funds flow from operations......................       340,246          69,696                 34           409,976
Debt repayments related to capital expenditures.       (48,850)         (8,150)                 -           (57,000)
Enerplus cash flows.............................        16,870         (16,870)                 -                 -
Site restoration and abandonment costs incurred.         2,628            (633)                 -            (3,261)
Accruals........................................         5,560           2,249                  -             7,809
ARTC received...................................             -             567                  -               567
                                                   -------------   -----------------    -----------     --------------
Cash available for distribution ................      $316,454         $48,125            $    34          $364,613
                                                   -------------   -----------------    -----------     --------------
                                                   -------------   -----------------    -----------     --------------
Cash available for distribution per Trust Unit..         $5.67                                                $5.61
                                                   -------------                                        --------------
                                                   -------------                                        --------------
</TABLE>

                                      A-3
<PAGE>

                             ENERPLUS RESOURCES FUND
            NOTES TO THE PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
                                DECEMBER 31, 2001
                                   (UNAUDITED)

1.   BASIS OF PRESENTATION

The accompanying unaudited pro forma consolidated financial statements (the "Pro
Forma Statements") of Enerplus Resources Fund ("Enerplus") have been prepared by
management of Enerplus in accordance with Canadian generally accepted accounting
principles for inclusion in the Renewal Annual Information Form of Enerplus
dated April 10, 2002.

Effective June 21, 2001, Enerplus acquired all of the outstanding trust units of
EnerMark Income Fund ("EnerMark") in exchange for 43,525,961 Trust Units of
Enerplus, and all of the outstanding warrants to acquire EnerMark trust units
were exchanged for 2,507,330 warrants to acquire Trust Units of Enerplus (the
"Merger"). As a result of this exchange, the Unitholders of EnerMark became the
controlling Unitholders of Enerplus. Accordingly, the Merger was accounted for
as a reverse take-over. Under this form of purchase accounting, the net assets
of Enerplus, rather than of EnerMark, are deemed to have been acquired.

The Pro Forma Statements of income and cash available for distribution have been
prepared from the audited consolidated statements of income and cash available
for distribution of Enerplus for the year ended December 31, 2001 and the
financial records of Enerplus for the period from January 1, 2001 to June 21,
2001. The Pro Forma Statements should be read in conjunction with the audited
consolidated financial statements of Enerplus for the year ended December 31,
2001. Other information which was available at the time of preparation of the
Pro Forma Statements has also been considered. In the opinion of management,
these Pro Forma Statements include all material adjustments necessary for a fair
presentation.

THE PRO FORMA STATEMENTS ARE NOT NECESSARILY INDICATIVE OF THE RESULTS OF
OPERATIONS WHICH WOULD HAVE OCCURRED FOR THE YEAR ENDED DECEMBER 31, 2001 HAD
THE MERGER BEEN EFFECTED ON JANUARY 1, 2001 AND, THEREFORE, MAY NOT BE
REPRESENTATIVE OF THE OPERATING RESULTS OF FUTURE PERIODS.

IN PREPARING THE PRO FORMA STATEMENTS, NO ADJUSTMENTS HAVE BEEN MADE TO
RECOGNIZE ANY OPERATING EFFICIENCIES OR GENERAL AND ADMINISTRATIVE COST SAVINGS
WHICH WOULD BE EXPECTED TO OCCUR AS A RESULT OF COMBINING THE OPERATIONS OF
ENERPLUS AND ENERMARK.

2.   PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

The pro forma consolidated statements of income and cash available for
distribution for the year ended December 31, 2001 give effect to the Merger if
it had occurred on January 1, 2001.

The accounting policies used in preparing the Pro Forma Statements are in
accordance with those disclosed in the audited consolidated financial statements
for Enerplus for the fiscal year ended December 31, 2001.

The Pro Forma Statements give effect to the following assumptions and
adjustments:

     (a)  Enerplus' Alberta Royalty Tax Credit ("ARTC") for the period from
          January 1, 2001 to June 21, 2001 has been eliminated.

     (b)  Management fees have been adjusted to reflect the change in the
          management agreement between Enerplus and Enerplus Global Energy
          Management Company and have been provided for at 2.75% of oil and gas
          revenues plus ARTC, net of Crown, freehold and other royalties and
          operating expenses in accordance with the new management agreement.

     (c)  Freehold and other royalties have been adjusted to reflect the
          acquisition of Enerplus Energy Services Ltd.'s residual royalty
          interest of 1% by EnerMark Inc.

     (d)  The provision for depletion, depreciation and amortization has been
          adjusted as a result of the increase in property, plant and equipment.

                                      A-4
<PAGE>

                             ENERPLUS RESOURCES FUND

         PRIOR TO JUNE 1, 2002                    FOLLOWING JUNE 1, 2002

         Western Canadian Place                        The Dome Tower
    Suite 1900, 700 - 9th Avenue S.W.           3000, 333 - 7th Avenue S.W.
        Calgary, Alberta, Canada                  Calgary, Alberta, Canada
                 T2P 3V4                                  T2P 2Z1

                            Telephone: (403) 298-2200
                            Fax:       (403) 298-2211<PAGE>

                                                                    EXHIBIT 4.4

Momentum

o Enerplus Unitholders received record cash distributions in 2001

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis of financial results is to be read in
conjunction with the audited consolidated financial statements as at, and for
the years ended December 31, 2001 and 2000, and is based on information
available to March 1, 2002. All amounts are stated in Canadian dollars unless
otherwise specified.

2001 HIGHLIGHTS

o    On June 21, 2001, the Unitholders of Enerplus Resources Fund and EnerMark
     Income Fund agreed to combine the two funds and continue as Enerplus
     Resources Fund. This created North America's largest and most liquid
     conventional oil and natural gas income fund with an enterprise value of
     approximately $2 billion.

o    In connection with the combination of the two funds, Enerplus restructured
     its management fee to better align the interests of the Manager and the
     Unitholders by eliminating acquisition and divestment fees and replacing
     them with performance incentive fees.

o    Aside from the reverse takeover combination of Enerplus and EnerMark,
     acquisitions net of dispositions of producing oil and gas properties
     totaled $8.9 million during the year ($77.4 million in acquisitions less
     $68.5 million in dispositions of non-core properties). The Fund avoided
     high cost acquisitions in a high priced environment for much of 2001 as a
     result of its disciplined bidding strategy.

o    Enerplus invested $143 million in development projects in 2001, drilling a
     record 350 net wells.

o    Enerplus' commodity price risk management program generated a net gain of
     $50.1 million for the year, demonstrating the value of such a program
     during periods of price volatility.

o    On November 15, 2001, the Fund issued 4,312,500 Trust Units at $24.75 per
     unit in a successful Canadian equity issue.

COMBINATION OF ENERMARK AND ENERPLUS

On June 21, 2001, the respective Unitholders of the EnerMark Income Fund
("EnerMark") and the Enerplus Resources Fund ("Enerplus") overwhelmingly
approved a merger combining the two funds. As the former Unitholders of EnerMark
held approximately 69% of the outstanding Trust Units of the combined Fund at
the date of acquisition, the merger has been accounted for using the reverse
takeover method of accounting for business combinations. For accounting
purposes, EnerMark acquired Enerplus effective June 21, 2001 and continues as
Enerplus Resources Fund which has a 16 year history, market recognition and a
listing on the New York Stock Exchange.

IMPORTANT INFORMATION REGARDING COMPARATIVE FINANCIAL STATEMENTS

With the reverse takeover method of accounting, the audited consolidated
financial statements presented herein include the accounts of EnerMark as at,
and for the twelve months ended December 31, 2001, plus the results of Enerplus
for the 193-day period from June 21, 2001 to December 31, 2001. In addition, the
historical comparative financial information for the year 2000 presented in the
audited consolidated financial statements is solely that of EnerMark.

In other words, the financial statements do not reflect the pre-acquisition
Enerplus results for the period from January 1, 2001 to June 20, 2001, nor do
they include the pre-acquisition results of Enerplus for the year ending
December 31, 2000.

The remaining discussion and analysis refers to Enerplus as the combined Fund,
and information included herein has been restated, as applicable, to reflect the
Trust Unit exchange ratio of 1.000 EnerMark Unit for 0.173 Enerplus Unit,
pursuant to the reverse takeover.

Comparison of 2001 results with those of 2000 is also complicated by the fact
that EnerMark, as predecessor to Enerplus, completed five major acquisitions
during 2000. Accordingly, the 2001 financial results include a full year of
operations for these acquisitions, while the 2000 results reflect only a
partial-year impact, commencing on the closing date of each acquisition as set
forth below:

<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------- ------------------ -----------------
Corporate and Property Acquisitions                                                     ($ millions)      Closing Date
--------------------------------------------------------------------------------- ------------------ -----------------
<S>                                                                                     <C>              <C>
Enerplus Resources Fund                                                                         $601     Jun. 21, 2001
Cabre Exploration Ltd. (purchase of remaining 11.35% interest)                                    32      Jan. 8, 2001
Cabre Exploration Ltd. (purchase of 88.65% interest)                                             260     Dec. 31, 2000
EBOC Energy Ltd.                                                                                 148      Sep. 1, 2000
Pursuit Resources Corp.                                                                           82      Apr. 3, 2000
Hanna/Garden Plains                                                                               35     Feb. 28, 2000
Western Star Exploration Ltd.                                                                     22      Jan. 7, 2000
--------------------------------------------------------------------------------- ------------------ -----------------
</TABLE>

RESULTS OF OPERATIONS

PRODUCTION

As a result of changing practices in the oil and gas industry in Canada,
Enerplus has adopted the standard of 6 Mcf:1 barrel of oil equivalent when
converting natural gas to barrels of oil equivalent ("BOE"). In accordance with
Canadian practice, production volumes, reserve volumes and revenues are reported
on a gross basis, before deduction of Crown and other royalties, unless
otherwise indicated.

Daily production averaged 54,015 BOE per day during 2001, representing a 74%
increase over production volumes of 31,112 BOE per day the previous year. The
increase is attributed to the reverse takeover of Enerplus by EnerMark on June
21, 2001, as well as the previously mentioned acquisitions during 2000. The
acquisitions in 2000 had a full year impact on 2001 production, but only a
partial-year impact on 2000 production, relative to the respective closing date
of the acquisition.

Enerplus' production is widely distributed across more than 250 properties in
Alberta, Saskatchewan and British Columbia. The largest 10 properties account
for 31% of Enerplus' production. This wide distribution minimizes the risk that
production might be materially impacted by the performance of a few major
properties.

Average production volumes for the years ended December 31, 2001 and 2000 are
outlined below:

<TABLE>
<CAPTION>
--------------------------------------------------------------- ------------------ ----------------- -----------------
Daily Production Volumes                                                   2001(1)              2000          % Change
--------------------------------------------------------------- ------------------ ----------------- -----------------
<S>                                                                        <C>               <C>              <C>
Natural gas (Mcf/day)                                                      176,671           101,473               74%
Crude oil (bbls/day)                                                        20,592            12,089               70%
Natural gas liquids (bbls/day)                                               3,978             2,111               88%
Total daily sales (BOE/day)                                                 54,015            31,112               74%
--------------------------------------------------------------- ------------------ ----------------- -----------------
</TABLE>

..2001 production reflects only 193 days of the post-merger Enerplus production
(from June 21, 2001 to December 31, 2001) after the date of the reverse takeover

Enerplus' exit production rate averaged 62,300 BOE per day for the month of
December 2001, with a weighting of 56% natural gas, 37% crude oil, and 7%
natural gas liquids. Production is currently expected to average 61,000 BOE per
day in 2002, after considering a full-year impact from the reverse takeover of
Enerplus and a forecast $130 million in development capital spending, but
without taking into account any further acquisitions.

PRICING AND PRICE RISK MANAGEMENT

The average price that Enerplus received for its natural gas (before hedging)
increased 9% from $4.52/Mcf in 2000 to $4.91/Mcf in 2001. In comparison, the
AECO monthly index increased 25% from $5.02/Mcf in 2000 to $6.30/Mcf in 2001 and
the NYMEX index price increased 12% from $3.91/Mcf in 2000 to $4.38/Mcf in 2001.
Enerplus' realized gas prices did not increase as much as the reference indices
due to:

o    Long-term fixed price physical delivery contracts representing
     approximately 5% of production that were priced below prevailing index
     prices in 2001; and

<PAGE>

o    Sales to aggregators that were also priced below prevailing indices in 2001
     because they reflect a basket of fixed, floating, and downstream delivery
     contracts.

The average price that Enerplus received for its crude oil (before hedging)
decreased 15% from CDN$35.86/bbl in 2000 to CDN$30.48/bbl in 2001. This reflects
a comparable 14% decline in the pricing of benchmark West Texas Intermediate
(WTI) crude oil. Enerplus benefited from the weaker Canadian exchange rate and a
lighter average blend of crude oil as a result of recent acquisitions, however,
these advantages were offset by wider price differentials on heavier streams of
crude oil during the year.

The realized prices for natural gas liquids ("NGLs") decreased 4% from the
previous year to average $31.12/bbl in 2001. However, the price of NGLs as a
proportion of Enerplus' crude oil price increased from 90% in 2000 to 102% in
2001 reflecting significantly higher values attributed to ethane production in
the first half of 2001.

<TABLE>
<CAPTION>
---------------------------------------------------------------------- --------------- --------------- ---------------
Average Selling Price (CDN$) Before the Effects of Hedging                        2001            2000        % Change
---------------------------------------------------------------------- --------------- --------------- ---------------
<S>                                                                             <C>             <C>           <C>
Natural gas (per Mcf)                                                           $ 4.91          $ 4.52             9%
Crude oil (per bbl)                                                              30.48           35.86           (15)%
Natural gas liquids (per bbl)                                                    31.12           32.33            (4)%
TOTAL DAILY SALES (PER BOE)                                                     $29.89          $30.94            (3)%
---------------------------------------------------------------------- --------------- --------------- ---------------
---------------------------------------------------------------------- --------------- --------------- ---------------
</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------- --------------- --------------- ---------------
Benchmark Pricing                                                                 2001            2000        % Change
---------------------------------------------------------------------- --------------- --------------- ---------------
<S>                                                                            <C>             <C>            <C>
AECO natural gas (per Mcf)                                                     $  6.30         $  5.02            25%
NYMEX natural gas (US$ per Mcf)                                                   4.38            3.91            12%
WTI crude oil (US$ per bbl)                                                      25.97           30.19           (14)%
CDN$/US$ exchange rate                                                         $0.6458         $0.6736            (4)%
---------------------------------------------------------------------- --------------- --------------- ---------------
</TABLE>

Enerplus has an on-going commodity price risk management program that is
designed to provide price protection on a portion of its future production in
the event of adverse commodity price movement, while retaining significant
exposure to upside price movements. The program is intended to provide a measure
of stability to the Fund's cash distributions as well as ensure Enerplus
realizes positive economic returns from its capital development and acquisition
activities.

In 2001, Enerplus realized a gain of $50.1 million as a result of its price risk
management program, as outlined below:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------- --------------- --------------
Opportunity Gain (Loss) from Financial Hedging ($ millions)                                      2001           2000
------------------------------------------------------------------------------------- --------------- --------------
<S>                                                                                             <C>            <C>
Crude oil                                                                                       $ 5.5         $ (9.6)
Natural gas                                                                                      44.6            0.5
                                                                                      --------------- --------------
Net hedging opportunity gain (loss)                                                             $50.1         $ (9.1)
                                                                                      --------------- --------------
                                                                                      --------------- --------------
Net gain (loss) per bbl crude oil                                                               $0.73         $(2.19)
Net gain (loss) per Mcf natural gas                                                             $0.69         $ 0.01
------------------------------------------------------------------------------------- --------------- --------------
------------------------------------------------------------------------------------- --------------- --------------
</TABLE>

Enerplus' commodity risk management position as at December 31, 2001 is
described in Note 8 to the financial statements. Commodity price risk is managed
through fixed price physical delivery contracts and financial instruments such
as forward contracts. The net receipts or payments arising from the forward
contracts are recognized in income as a component of oil and gas sales during
the same period as the corresponding hedge position. At December 31, 2001,
Enerplus had $4.6 million in deferred costs related to forward contracts that
will be amortized over the remaining life of those instruments. The
mark-to-market value of the financial forward contracts represented an
unrealized loss of $0.4 million with reference to year-end prices and forward
markets.

<PAGE>

Subsequent to year end, on January 8, 2002, Enerplus entered into an additional
3-way financial option on 1,500 bbls/day of oil from April 2002 to December
2003. Under the terms of this option Enerplus purchased a WTI put at
US$19.50/bbl, sold a WTI call at US$27.00/bbl and sold a WTI put at
US$17.00/bbl. Enerplus also entered into a 3-way option on 9,480 Mcf/day of
natural gas for the period from April to October 2002, selling an AECO call at
$4.22/Mcf, purchasing an AECO put at $3.29/Mcf and selling an AECO put at
$2.37/Mcf. The cost of this gas price protection was mitigated by selling an
AECO call at $6.33/Mcf for the period from November 2002 to March 2003.

In the future, Enerplus intends to continue to manage its commodity price
exposure in a similar manner with the objective of establishing downside price
protection at a reasonable cost, while maintaining exposure to improving prices.
The future gain or loss from such a program depends on forward markets and
future prices. Readers are cautioned that the significant hedging gains
experienced in 2001 are not expected to be replicated in 2002.

REVENUES

Crude oil and natural gas revenues, including hedging gains, were $639.4 million
for the year ended December 31, 2001, which was 86% higher than the $343.2
million reported for the year ended December 31, 2000. This substantial increase
was due to the reverse takeover of Enerplus on June 21, 2001, as well as the
acquisitions of Cabre, EBOC, Pursuit, and Western Star and the acquisition of
the Hanna/Garden Plains property during 2000. The acquisitions in 2000 had a
full year impact on 2001 revenues, but only a partial-year impact on 2000
revenues, depending on the closing date of the acquisition. Enerplus' 2001
increase in revenues was primarily the result of lighter production volumes and
hedging gains offset by a slight reduction in prices as described in the table
below.

<TABLE>
<CAPTION>
-------------------------------------------------------------- -------------- -------------- ------------- -----------
                                                                    Crude Oil            NGL   Natural Gas       Total
Analysis of Sales Revenues ($ millions)                              Revenues       Revenues      Revenues    Revenues
-------------------------------------------------------------- -------------- -------------- ------------- -----------
<C>                                                                 <C>             <C>        <C>            <C>
2000 Sales Revenues                                                    $149.0          $25.0        $169.2      $343.2
Price variance                                                          (40.4)          (1.8)         25.1       (17.1)
Volume variance                                                         110.8           22.0         121.3       254.1
Hedging gain variance                                                    15.1            -            44.1        59.2
-------------------------------------------------------------- -------------- -------------- ------------- -----------
2001 SALES REVENUES                                                    $234.5          $45.2        $359.7      $639.4
-------------------------------------------------------------- -------------- -------------- ------------- -----------
-------------------------------------------------------------- -------------- -------------- ------------- -----------
</TABLE>

ROYALTIES

Royalties increased by $51.7 million to $132.7 million for the year ended
December 31, 2001, as a consequence of the increase in production revenue. The
royalty rate before hedging for the year ended December 31, 2001, decreased to
22.5% from 23.0% for the year 2000. In the current commodity price environment,
Enerplus expects a royalty rate of approximately 21% for 2002, without taking
into account future acquisitions.

OPERATING EXPENSES

Operating expenses increased to $120.1 million for the year ended December 31,
2001 from $55.0 million in 2000, due mainly to the higher production volumes
associated with acquisition activities. This represents a cost of $6.09/BOE in
2001 compared to $4.83/BOE in 2000. Increased activity levels in the industry
during the first nine months of 2001 created a higher demand for goods and
services and placed a corresponding upward pressure on costs. In addition,
Enerplus experienced higher electricity costs in the first half of 2001 compared
to 2000. Finally, the acquisition of properties during 2000 and 2001 with
relatively higher operating costs than the pre-existing property portfolio added
to Enerplus' operating cost per BOE.

Lower electricity costs and reduced activity levels in the industry are expected
to stabilize and moderate Enerplus' operating expenses in 2002.

<PAGE>

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses were $13.0 million for the year ended
December 31, 2001 compared to $7.2 million for the year 2000. The increase
reflects the additional costs of managing entities acquired during 2000 for a
full year. General and administrative costs per BOE of production increased
marginally to $0.66/BOE for 2001 compared to $0.63/BOE for 2000.

In accordance with the full cost method of accounting, Enerplus capitalized $7.5
million of G&A costs in 2001 compared to $7.9 million capitalized in 2000. The
majority of these capitalized costs represent compensation costs for staff
involved in development drilling and acquisition activities.

In 2002 the Fund is targeting G&A costs of approximately $0.60/BOE, before
taking into account any further acquisitions.

MANAGEMENT FEES

Management services are supplied to Enerplus on a fee and cost reimbursement
basis. Management fees expensed were $9.3 million for the year ended December
31, 2001 represents an increase of $4.8 million over the year 2000 as a result
of higher operating income as well as the increase in the base management fee
percentage as discussed below relative to the restructuring of management fees
in their entirety.

In conjunction with the reverse takeover of Enerplus, a new management agreement
was approved by the Unitholders on June 21, 2001. Under the new agreement, base
management fees were set at 2.75% of operating income (compared to pre-June 21,
2001 rates of 2.2% for EnerMark and 3.5% for Enerplus). In addition, acquisition
and divestment fees (capitalized for financial statement purposes) were
eliminated and were replaced by performance fees based on both the total return
of the Fund, and its relative performance as compared to other senior
conventional oil and gas trusts. The performance fee can range between 0% and 4%
of operating income. In connection with the merger, the management company was
paid a fee of 172,500 Enerplus Trust Units with a value of $5 million in 2001,
which was capitalized as part of the merger cost. The management fee is
described in Note 6 to the financial statements.

In 2002, the base management fee will be 2.75% of the Fund's operating income.
In addition, there are two types of incremental performance fees which can range
in aggregate from 0% to 4%:

Total Return Performance Fee (minimum 0%, maximum 2% of the Fund's operating
income)

1.   If the total return of Enerplus Units (amount of distributions and
     appreciation in Trust Unit price) exceeds 11%, then the Total Return
     Performance Fee will be a minimum of 0.5%.

2.   If the total return of Enerplus Units is less than the yield on 10-year
     Government of Canada bonds plus 5%; then the Total Return Performance Fee
     will be 0% (subject to the minimum payment described in (1) above).

3.   If the total return of Enerplus Units exceeds the yield on 10-year
     Government of Canada bonds plus 15%; then the Total Return Performance Fee
     will be 2% of the operating income of the Fund.

4.   If the total return of Enerplus Units is between the yield on 10-year
     Government of Canada bonds plus a factor of 5% to 15% (subject to the
     minimum payment described in (1) above), then a sliding scale calculation
     (ranging from 0% to 2%) will be used.

Relative Performance Fee (minimum 0%, maximum 2% of the Fund's operating income)

1.   The relative performance of Enerplus as compared to seven other qualifying
     conventional oil and gas trusts will be ranked based on distributions and
     unit price appreciation.

2.   The Relative Performance Fee will be calculated using a percentage equal to
     2% divided by the number of trusts in the top half of the rankings
     multiplied by the number of rankings which Enerplus is below the number one
     ranking and subtracting the product obtained thereby from 2%; and

3.   If the resulting value obtained is less than zero, then no Relative
     Performance Fee will be paid, otherwise the Relative Performance Fee will
     be the amount obtained by multiplying the resulting percentage (not to
     exceed 2%) by the operating income of the Fund.

<PAGE>

In effect, Enerplus must rank at least fourth out of the eight largest
conventional oil and gas trusts (including Enerplus) before any Relative
Performance Fee is payable.

This fee arrangement will be reviewed annually with the Board of Directors. The
new management fee arrangements were designed to better align the interests of
the Manager with the interests of Unitholders.

INTEREST EXPENSE

Interest expense for the year 2001 was $17.6 million, up $2.3 million from 2000
due to higher outstanding bank debt incurred in connection with the acquisition
activities in 2000 and 2001. Bank debt increased to $412.6 million at December
31, 2001 from $275.9 million on December 31, 2000.

During 2001, Enerplus' interest costs were entirely based on floating rates, as
those rates offered the most cost-effective financing strategy. Subsequent to
the year end, Enerplus entered into an interest rate swap that fixed the rate on
a notional $25 million in debt for a three year term from January 18, 2002 to
January 18, 2005 at a rate of 3.89% per annum (before banking fees that are
expected to range between 0.85% and 1.05%). Enerplus may consider fixing an
additional portion of its interest rate exposure in 2002, depending on its
financing requirements and the forward interest rate market.

DEPLETION AND CEILING TEST

Depletion of the property, plant and equipment is provided on the
unit-of-production method based on constant price proven reserves. An estimate
of the future costs for restoration and abandonment of well sites and facilities
is updated annually and this cost estimate is amortized over the life of the
properties on a unit-of-production basis.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------- ------------- ------------
                                                                                                     2001         2000
------------------------------------------------------------------------------------------- ------------- ------------
<S>                                                                                                <C>           <C>
Depletion and depreciation                                                                         $181.1        $76.5
Amortization of future site restoration                                                               5.9          3.8
Amortization of deferred hedging costs                                                                7.1            -
                                                                                            ------------- ------------
Total                                                                                              $194.1        $80.3
------------------------------------------------------------------------------------------- ------------- ------------
------------------------------------------------------------------------------------------- ------------- ------------
</TABLE>

Depletion, depreciation and amortization increased to $194.1 million in 2001
from $80.3 million in 2000. Included in the amortization amount are $7.1 million
of amortized costs relating to the mark-to-market value of the Enerplus
commodity price forward contracts at the time of the reverse takeover. The
mark-to-market value of these contracts was recognized as either a deferred
hedge asset or liability as part of the acquisition cost and will be amortized
over the remaining term of the contract ending in 2004. The actual gain (or
loss) associated with this contract will be recognized in oil and gas sales as
they are realized.

The rate of depletion and depreciation has increased to $9.18/BOE in 2001 from
$6.72/BOE in 2000. The increase is the result of higher costs attributed to
petroleum and natural gas assets acquired during 2000 and 2001. The adoption of
the liability method of accounting for future income taxes, as required by
Canadian generally accepted accounting principles, had the effect of
substantially increasing the recorded value of acquired property, plant and
equipment compared to the previous deferral method of accounting. In the case of
the corporate acquisitions in 2000 the value of acquired assets were increased
to reflect any shortfall between the net book value and the cost basis for
income tax purposes.

Enerplus places a limit on the carrying value of property, plant and equipment
(the "ceiling test"). The cost of these assets, less accumulated depletion, is
limited to the estimated future net revenue from proved reserves (based on
unescalated prices and costs at the balance sheet date) less estimated future
general and administrative costs, financing costs, and management fees. There
was a surplus in the ceiling test at year end 2001.

TAXES

Capital taxes increased to $4.7 million for the year 2001 from $2.9 million in
2000 primarily due to the increase in capital structure.

For the year ended December 31, 2001, a future income tax recovery of $31.5
million was recorded in income. Under Canadian generally accepted accounting
principles, the Fund does not recognize any future income taxes, as taxable
income is distributed to Unitholders in the form of taxable distributions.

<PAGE>

However, the Fund's operating companies are required to account for future
income taxes. Future income taxes arise because of the difference between the
accounting and tax bases of the operating companies' assets and liabilities.

NETBACKS

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------- ----------- -----------
Netbacks per BOE of Production (6:1) year ended December 31,                                       2001        2000
------------------------------------------------------------------------------------------- ----------- -----------
<S>                                                                                              <C>         <C>
Oil and gas sales                                                                                $32.43      $30.14
Royalties                                                                                         (6.73)      (7.10)
Operating expenses                                                                                (6.09)      (4.83)
General and administrative expenses                                                               (0.66)      (0.63)
Management fees                                                                                   (0.47)      (0.40)
Interest expense, net of interest and other income                                                (0.85)      (1.30)
Capital taxes                                                                                     (0.24)      (0.26)
Restoration and abandonment cash costs                                                            (0.13)      (0.13)
                                                                                            ----------- -----------
         Funds flow from operations                                                               17.26       15.49
Depletion and depreciation                                                                        (9.18)      (6.72)
Amortization, net of cash costs                                                                   (0.54)      (0.21)
Future income tax recovery (provision)                                                             1.60       (1.35)
                                                                                            ----------- -----------
         Net income per BOE of production                                                        $ 9.14      $ 7.21
------------------------------------------------------------------------------------------- ----------- -----------
</TABLE>

NET INCOME AND FUNDS FLOW FROM OPERATIONS

Net income for the year ended December 31, 2001 was $180.3 million, or $3.28 per
Trust Unit, up 119% (7% per Trust Unit) from $82.2 million or $3.06 per Trust
Unit for the year 2000. After adding back non-cash expenses such as depletion,
depreciation, amortization and the future income tax provision (recovery), the
resultant Funds Flow from Operations was $340.2 million in 2001 or $6.20 per
Trust Unit compared to $176.4 million or $6.57 per Trust Unit in 2000.

QUARTERLY FINANCIAL INFORMATION

<TABLE>
<CAPTION>
--------------------------------------------------------------- ------------- ------------ ---------------------------
                                                                  Oil and Gas                      Net income per Unit
                                                                  Revenue Net          Net ---------------------------
$ millions, except per Unit amounts                              of Royalties       Income         Basic       Diluted
--------------------------------------------------------------- ------------- ------------ ------------- -------------
<S>                                                              <C>                <C>            <C>         <C>
2001
First quarter                                                          $136.7       $ 59.7         $1.42         $1.41
Second quarter                                                          109.3         58.5          1.30          1.29
Third quarter                                                           130.9         25.1          0.39          0.39
Fourth quarter                                                          129.8         37.0          0.55          0.55
                                                                ------------- ------------
TOTAL                                                                  $506.7       $180.3         $3.28         $3.28
--------------------------------------------------------------- ------------- ------------ ------------- -------------
--------------------------------------------------------------- ------------- ------------ ------------- -------------
2000
First quarter                                                          $ 43.5       $ 10.1         $0.45         $0.45
Second quarter                                                           55.4         10.9          0.42          0.42
Third quarter                                                            68.6         23.9          0.88          0.88
</TABLE>

<TABLE>
<S>                                                              <C>                <C>            <C>         <C>
Fourth quarter                                                           94.7         37.3          1.16          1.16
                                                                ------------- ------------
TOTAL                                                                  $262.2       $ 82.2         $3.06         $3.05
--------------------------------------------------------------- ------------- ------------ ------------- -------------
--------------------------------------------------------------- ------------- ------------ ------------- -------------
</TABLE>

<PAGE>

CASH AVAILABLE FOR DISTRIBUTION

Enerplus distributes the net cash flow from its oil and gas properties to the
Trust Unitholders on a monthly basis. A portion of this cash flow is typically
withheld to repay bank debt incurred with respect to acquisitions and capital
spending. For the year ended December 31, 2001, Enerplus generated $340.2
million in Funds Flow from Operations. Of this amount (together with certain
funds described in the following table), $316.5 million was paid to Unitholders
and $48.8 million was retained for debt reduction.

Management monitors the Fund's distribution payout policy with respect to
forecast cash flows, debt levels, and spending plans. The level of cash retained
for debt repayment typically varies between 5% and 10% of total cash flow,
although management is prepared to adjust the payout levels in an effort to
balance the investor's desire for distributions with the Fund's requirement to
maintain a prudent capital structure.

The following table reconciles Enerplus' "Funds Flow from Operations" as per the
Statement of Cash Flows with the cash available for distribution to Unitholders.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------- -------------- -------------
Reconciliation of Cash Available for Distribution for the year ended December 31,
$ millions, except per Unit amounts                                                                 2001          2000
----------------------------------------------------------------------------------------- -------------- -------------
<S>                                                                                               <C>           <C>
Funds flow from operations                                                                        $340.2        $176.4
Site restoration and abandonment costs incurred                                                      2.6           1.4
Cash withheld for debt reduction                                                                   (48.8)        (11.7)
Enerplus cash flows (Note A)                                                                        16.9             -
Accruals (Note B)                                                                                    5.6             -
Pursuit cash flows, net of debt reduction (Note C)                                                    -            2.1
                                                                                          -------------- -------------
Cash available for distribution (Note D)                                                          $316.5        $168.2
                                                                                          -------------- -------------
Cash available for distribution per Trust Unit                                                    $ 5.67        $ 5.49
----------------------------------------------------------------------------------------- -------------- -------------
</TABLE>

Cash available for distribution per Trust Unit of $5.67 for 2001 represent what
an EnerMark Unitholder would have received for the 2001 production year (which
was paid to Unitholders from March 20, 2001 to February 20, 2002) after
converting 1 EnerMark Unit for 0.173 Enerplus Unit pursuant to the terms of the
Merger. Similarly, cash available for distribution of $5.49 per Trust Unit for
the 2000 production year was paid to EnerMark Unitholders between March 20, 2000
and February 20, 2001.

Note A:   As a result of the reverse takeover, funds flow from operations do
          not include funds earned by the former Enerplus prior to June 21,
          2001. However, cash distributions include the July/August payment in
          respect of this cash flow. As a result, the July/August payment to
          Unitholders is added to funds flow from operations for purposes of
          this reconciliation.

Note B:   According to the current Royalty Agreement with Enerplus Resources
          Corporation, the royalty paid to the Fund must be on a cash basis. As
          a consequence, the change in accrued net revenues for the year are
          added back to funds flow from operations for purposes of this
          reconciliation.

Note C:   In the acquisition of Pursuit Resources Corp., Enerplus distributed
          a portion of the Pursuit net cash flow generated between the effective
          date and the closing date of the acquisition.

Note D:   The cash for distribution of $316.5 million in 2001 can be reconciled
          to the cash paid to Unitholders of $328.9 million on the Statement of
          Cash Flows by subtracting the January and February 2001 payments to
          Unitholders and adding the January and February 2002 payments to
          Unitholders, as the Statement of Cash Flows reflects cash payments to
          Unitholders during the calendar year.

<PAGE>

CAPITAL EXPENDITURES

During the year ended December 31, 2001, Enerplus spent $152.2 million (2000 -
$65.8 million) on capital expenditures and acquisitions net of divestitures.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------- ----------- -----------
Capital Expenditures for the year ended December 31, $ millions                                     2001        2000
-------------------------------------------------------------------------------------------- ----------- -----------
<S>                                                                                               <C>          <C>
Development drilling and completions                                                              $ 83.0      $ 27.1
Plant and facilities                                                                                53.6        11.9
Office and other expenditures                                                                        6.7         1.0
                                                                                             ----------- -----------
       Total                                                                                       143.3        40.0
Acquisitions of oil and gas properties                                                              77.4        51.1
Dispositions of oil and gas properties                                                             (68.5)      (25.3)
                                                                                             ----------- -----------
       Total Net Capital Expenditures                                                             $152.2      $ 65.8
-------------------------------------------------------------------------------------------- ----------- -----------
-------------------------------------------------------------------------------------------- ----------- -----------

Enerplus finances its capital expenditures through bank borrowing, new equity issues, and by withholding a portion
of funds flow from operations. The following table outlines the development spending by major property:

</TABLE>

<TABLE>
<CAPTION>
---------------------------------------------- -------------------------------------------------------- --------------
                                                                         2001                                     2000
                                               -------------------------------------------------------- --------------
Capital Expenditures for the year                Development
($ millions) ended December 31,                     Drilling     Facilities         Other         Total          Total
---------------------------------------------- ------------- -------------- ------------- ------------- --------------
<S>                                              <C>             <C>                <C>          <C>             <C>
Hanna/Garden Plains                                    $11.5          $11.9          $1.7        $ 25.1          $ 3.5
Pembina Five Way                                         7.2            1.7             -           8.9              -
Medicine Hat                                             6.7            5.8             -          12.5            0.5
Bantry                                                   7.7            2.3             -          10.0            1.9
Benjamin                                                 2.4            3.2           0.1           5.7            1.4
Giltedge                                                 0.4            3.8             -           4.2            9.7
Other                                                   47.1           24.9           4.9          76.9           23.0
                                               ------------- -------------- ------------- ------------- --------------
Total                                                  $83.0          $53.6          $6.7        $143.3          $40.0
---------------------------------------------- ------------- -------------- ------------- ------------- --------------
---------------------------------------------- ------------- -------------- ------------- ------------- --------------
</TABLE>

Enerplus is currently forecasting capital expenditures of approximately $130
million in 2002 on existing properties. Of this total, Enerplus expects to spend
$20 million at Joarcam drilling 18 potential oil wells and 5 potential gas
wells, recompleting 30 wells, and increasing the facility infrastructure
capacity in the region. At Hanna/Garden Plains, Enerplus expects to spend $12
million drilling 75 shallow gas wells, performing well workovers and completing
facility modifications. At Medicine Hat North, the capital budget of $9 million
includes drilling 50 potential gas wells and installation of compression in the
region. At Bantry, Enerplus expects to spend $5 million drilling 37 potential
gas wells and refracing existing wells.

Enerplus routinely evaluates its property portfolio and disposes of properties
that are viewed as non-core holdings with limited contribution to cash flow or
upside development potential. In 2001, Enerplus sold $68.5 million worth of
non-core oil and gas properties. Offsetting these dispositions were $77.4
million of acquisitions for the year, including $25.0 million on Kaybob, $8.8
million on Ferrier, and $8.3 million on Gleneath. Enerplus expects to continue
its process of rationalizing marginal properties and acquiring new properties in
2002.

LIQUIDITY AND CAPITAL RESOURCES

Enerplus' bank debt increased to $412.6 million as at December 31, 2001 compared
to $275.9 million at December 31, 2000.

<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------- ----------- ------------
Continuity of Bank Debt ($ millions)                                                                 2001         2000
--------------------------------------------------------------------------------------------- ----------- ------------
<S>                                                                                                <C>          <C>
Beginning balance January 1,                                                                       $275.9       $131.3
Items that affect bank debt as per Statement of Cash Flows
Purchase of property, plant and equipment                                                           243.0        251.9
Proceeds on sale of property, plant and equipment                                                   (75.3)       (18.5)
Assumption of acquired entities' bank debt                                                           78.6         66.9
Proceeds from issue of Trust Units                                                                 (151.4)      (120.6)
Cash distributions paid to Unitholders during the calendar year                                     328.9        132.6
Funds flow from operating activities (on an accrued basis)                                         (340.2)      (176.4)
Increase in non-cash operating working capital                                                       52.9         11.4
Other                                                                                                 0.2         (2.7)
                                                                                              ----------- ------------
Ending Bank Debt December 31,                                                                      $412.6       $275.9
                                                                                              ----------- ------------
Bank Debt per Trust Unit at December 31,                                                           $ 5.93       $ 6.74
--------------------------------------------------------------------------------------------- ----------- ------------
</TABLE>

As at March 1, 2002, Enerplus renegotiated its bank facilities and consolidated
the bank lines of the former EnerMark and Enerplus operating companies. Enerplus
currently has $620 million committed under the unsecured bank facilities with a
syndicate of 7 banks, comprised of a $590 million revolving 364 day committed
facility with an incremental amortizing two-year term, and an additional $30
million demand operating facility. These credit facilities have no financial
covenants, however, the size of the facility is based on the banks' evaluation
of the value of Enerplus' proven oil and gas reserves. The banks have reserved
the right to revise the commitment based on a review of the year end reserve
information. The bank debt has priority over claims of and distributions to the
Unitholders. However, Unitholders have no direct liability with respect to the
bank loan should revenues be insufficient to repay it.

In the event that the revolving bank line is not extended at the end of the 364
day revolving period, no payments are required to be made to non-extending
lenders during the first year of the term period. However, Enerplus will be
required to maintain certain minimum balances on deposit with the syndicate
agent.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------- ------------ ------------
Financial Leverage and Coverage                                                                      2001         2000
-------------------------------------------------------------------------------------------- ------------ ------------
<S>                                                                                                 <C>          <C>
Bank debt to funds flow from operations                                                              1.2x         1.6x
Funds flow from operations to interest expense                                                      19.3x        11.5x
Bank debt to bank debt plus equity                                                                    23%          27%
-------------------------------------------------------------------------------------------- ------------ ------------
</TABLE>

Enerplus has no off-balance sheet financing arrangements.

In 2002, Enerplus may consider replacing a portion of its bank debt with term
debt (such as 5-10 year debentures) in order to diversify credit sources, secure
term financing commitments, and potentially fix interest rates for a longer
term.

NATURAL GAS PIPELINE COMMITMENTS

Enerplus has contracted to transport 10MMcf/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 Alliance Pipeline until
October 31, 2015.

<PAGE>

TRUST UNIT INFORMATION

Enerplus had 69,532,000 Trust Units and no warrants outstanding at December 31,
2001 compared to 40,925,000 Trust Units and 3,045,000 warrants at December 31,
2000. The weighted number of Trust Units outstanding during 2001 was 54,907,000
(2000 - 26,841,000).

During 2001, Enerplus issued 20,863,000 additional Trust Units pursuant to the
Merger agreement on June 21, 2001. In addition, 1,267,000 Trust Units were
issued to acquire the non-controlling interest with respect to the Cabre
acquisition, and 4,312,500 Trust Units were issued pursuant to the November 15,
2001 equity offering. Enerplus also issued 3,045,000 warrants on December 31,
2000 and an additional 390,000 warrants on January 8, 2001 pursuant to the Cabre
acquisition, of which 1,197,000 were exercised during 2001 and 2,238,000 expired
on December 17, 2001.

INCOME TAXES

The following sets out a general discussion of the Canadian and U.S. tax
consequences of holding Enerplus Trust Units as capital property. The summary is
not exhaustive in nature and is not intended to provide legal or tax advice.
Unitholders or potential Unitholders should consult their own legal or tax
advisors as to their particular tax consequences.

CANADIAN TAXPAYERS

The Fund qualifies as a mutual fund trust under the Income Tax Act (Canada) and,
accordingly, Trust Units of the Fund are qualified investments for RRSPs, RRIFs,
RESPs, and DPSPs. Each year, the Fund is required to file an income tax return
and any taxable income in the Fund is allocated to the Unitholders.

Unitholders are required to include in computing income their pro-rata share of
any taxable income earned by the Fund in that year. An investor's adjusted cost
base ("ACB") in a Trust Unit equals the purchase price of the Unit less any
non-taxable cash distributions received from the date of acquisition. To the
extent a Unitholder's ACB is reduced below zero, such amount will be deemed to
be a capital gain to the Unitholder and the Unitholder's ACB will be brought to
$nil.

Enerplus paid $6.25 per Trust Unit in cash distributions to Unitholders during
the 2001 calendar year. For Canadian tax purposes, 25% of these distributions,
or $1.54 per Unit was a tax deferred return of capital, 74% or $4.6269 per Unit
was taxable to Unitholders as other income, and 1% or $0.0831 per Unit was
taxable dividend income.

U.S. TAXPAYERS

U.S. Unitholders who receive cash distributions are subject to a 15% Canadian
withholding tax, applied to the taxable portion of the distribution as computed
under Canadian tax law. U.S. taxpayers may be eligible for a foreign tax credit
with respect to Canadian withholding taxes paid.

The taxable portion of the cash distribution for U.S. tax purposes is determined
by Enerplus in relation to its current and accumulated earnings and profits
using U.S. income tax principles. The taxable portion so determined is
considered to be a dividend for U.S. tax purposes.

The non-taxable portion of the cash distribution, is a return of the cost (or
other basis). The cost (or other basis) is reduced by this amount for computing
any gain or loss arising from disposition. However, if the full amount of the
cost (or other basis) has been recovered, any further non-taxable distributions
should be reported as gains.

Enerplus paid US$3.83 per Trust Unit to U.S. residents during the 2001 calendar
year, of which 13% or US$0.49 per Unit was a tax deferred return of capital and
87% or US$3.34 per Unit was a taxable dividend.

BUSINESS RISKS

Investors that purchase Enerplus Trust Units are participating in the net cash
flow from a portfolio of western Canadian crude oil and natural gas producing
properties. As such, the cash flow paid to investors and the value of Enerplus
Units are subject to numerous risk factors. These risk factors, many of which
are associated with the oil and gas industry, include, but are not limited to
the following influences:

<PAGE>

o    The prices that Enerplus receives for its crude oil, natural gas, and NGLs
     can fluctuate significantly due to global and North American supply and
     demand, worldwide economic conditions, weather, political stability,
     Canada/U.S. exchange rates, the proximity to and capacity of transportation
     and processing facilities, the price and availability of alternative fuels
     and government regulations. Declines in oil or natural gas prices will have
     an adverse effect on our operations, financial condition, reserves and
     ultimately our ability to pay distributions to Trust Unitholders.

o    Oil and natural gas reserves naturally deplete as they are produced over
     time. Enerplus' ability to replace production depends on its success in
     acquiring new reserves and developing existing reserves. Since Enerplus
     distributes the majority of its net cash flow to Unitholders, it must
     finance a large portion of this acquisition and development activity
     through continued access to the equity and debt capital markets. As such,
     it is dependent on continued access to the capital markets to maintain and
     grow value for Unitholders.

o    Acquisition of oil and gas assets depend on Enerplus' assessment of value
     at the time of acquisition. Incorrect assessments of value can adversely
     affect distributions to Unitholders and the value of the Trust Units.

o    The value of Enerplus Trust Units is based on the underlying value of the
     oil and gas reserves. Geological and operational risks can affect the
     quantity and quality of reserves and the cost of ultimately recovering
     those reserves. Lower oil and natural gas prices increase the risk of
     write-downs of Enerplus' oil and gas property investments.

o    Changing interest rates can affect borrowing costs and the market price of
     yield-based investments such as Enerplus.

o    Government royalties, income tax laws, environmental laws and regulatory
     requirements can have a significant financial and operational impact on
     Enerplus.

o    Operating costs may be difficult to control as increased activity in the
     oil and gas industry may increase the cost of goods and services and make
     it difficult to hire and retain staff.

o    Third party operators operate approximately 35% of Enerplus' production,
     which reduces Enerplus' ability to control costs, capital, and operation
     activities with respect to these properties.

o    Enerplus assumes customer credit risk associated with oil and gas sales,
     financial hedging transactions, and joint venture participants.

o    Environmental and safety risks influence the workforce, operating costs,
     and compliance with regulatory standards.

Enerplus has no control over many of these risk factors. Nevertheless,
management has attempted to mitigate some of these risks through the following:

o    Enerplus has an ongoing commodity price risk management strategy that is
     intended to provide price protection on a portion of its future production
     in the event of adverse commodity price movement, while retaining exposure
     to upside price movements.

o    Enerplus has listings on the Toronto and New York Stock exchanges and
     maintains an active investor relations program designed to facilitate
     access to equity capital markets.

o    Enerplus maintains a prudent capital structure by retaining a portion of
     the cash flow for debt repayment, rationalizing properties that no longer
     meet portfolio guidelines, managing capital expenditures within rate of
     return guidelines, and utilizing the equity markets when appropriate.

o    Acquisitions are subject to stringent investment criteria, due diligence,
     and review and approval by the Fund's Board of Directors. Independent
     reservoir engineers evaluations are required for acquisitions in excess of
     $5 million.

o    Enerplus strives to acquire low risk, mature properties with a high
     proportion of proven reserves, high cash netbacks, long reserve lives, and
     predictable production.

o    Similarly, Enerplus participates in lower-risk development projects, while
     farming out or monetizing higher risk exploratory prospects.

<PAGE>

o    Each year a significant portion of Enerplus' proven and probable oil and
     gas reserves are evaluated by a firm of independent reservoir engineers.
     Approximately 83% of the net present value of the total established
     reserves discounted at 12% were evaluated at December 31, 2001. A special
     committee of the Board of Directors reviews and approves the reserve
     report.

o    Enerplus monitors the interest rate forward market and has recently begun
     to fix the interest rate on a portion of its debt through interest rate
     swaps for terms up to 3 years. In addition, the Fund may consider fixing
     longer-term interest rates in conjunction with the issuance of longer-term
     debentures.

o    Management has established credit policies and controls designed to limit
     the risk of default or nonpayment with respect to oil and gas sales,
     financial hedging transactions, and joint venture participants.

o    Enerplus offers competitive incentive-based compensation packages to
     attract and retain qualified staff.

o    Enerplus has employee training and safety programs designed to educate on
     safety awareness, monitor incidents and prevent accidents.

o    Enerplus has a site inspections program and a corrosion risk management
     program designed to ensure compliance with environmental laws and
     regulations.

o    Enerplus maintains certain insurance coverages related to liability and
     property exposures.

BUSINESS PROSPECTS

Enerplus strives to be the premier oil and gas income fund in North America by
continuing to deliver top quartile returns to its Unitholders. The Fund's
objective is to increase value for Unitholders through successful acquisitions
and the low-risk development of its existing properties utilizing technology,
creativity and innovation.

Enerplus offers investors the benefits of owning a diversified portfolio of
mature crude oil and natural gas producing properties and related facilities. As
such, the most influential factor affecting the future prospects of the Fund is
the price of crude oil and natural gas. Commodity prices continue to be volatile
and difficult to forecast.

Natural gas prices are expected to remain weak for the first part of 2002, or
until such time as economic and weather-related demand can reduce the current
North American storage oversupply. Over the longer term, Enerplus expects
natural gas prices to strengthen, although not to the elevated levels
experienced in the first quarter of 2001. A cyclical re-balancing of gas supply
is expected as reduced exploration and development drilling, combined with
natural reservoir depletion, reduces supplies at the same time North American
demand is recovering.

The price of crude oil has weakened since the third quarter of 2001 due to
reduced economic demand and the threat that OPEC may abandon its production
quota practices in an attempt to regain market share from non-OPEC nations.
Other developments, such as continued political instability in the Middle East,
natural reservoir declines, reduced exploration and development drilling, and
signs of a worldwide economic recovery are creating compensating upward pressure
on oil prices.

Enerplus has a price risk management strategy that is designed to provide a
measure of price protection in the event of adverse commodity price movement,
while retaining exposure to upside price movements. At year end, approximately
28% of Enerplus' expected natural gas production and 15% of its expected crude
oil production was protected against downward price movement. Even with these
positions, the Fund's cash flow remains sensitive to changes in commodity prices
as demonstrated by the following table:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------- -------------------------
                                                                                                        Effect on 2002
                                                                                                     Distributions per
Sensitivity to Changes in Price and Exchange Rate                                                           Trust Unit
-------------------------------------------------------------------------------------------- -------------------------
<S>                                                                                                  <C>
Change of CDN$0.10 per Mcf in the price of natural gas                                                           $0.07
Change of US$1.00 per barrel in the price of WTI crude oil                                                       $0.15
Change of 1,000 BOE/day in production                                                                            $0.06
Change of $0.01 in the US$/CDN$ exchange rate                                                                    $0.04
Change of 1% in interest rate                                                                                    $0.05
-------------------------------------------------------------------------------------------- -------------------------
</TABLE>

<PAGE>

As with most yield-based investments, the level of interest rates can have an
impact on the trading value of Enerplus Trust Units. The recent period of
declining interest rates has had a positive impact on Enerplus' Trust Unit value
and the Fund's ability to raise capital. While the prospect of an economic
recovery may reverse the current trend of low interest rates, such a recovery
would be positive for the oil and natural gas markets, and it is expected that
the benefits associated with a commodity price recovery far outweighs the risk
of rising short-term interest rates.

The combination of Enerplus and EnerMark has created the largest conventional
oil and gas income fund in North America. It has increased liquidity for
investors and attracted a broader base of institutional and U.S. investors
through its listings on the TSE and NYSE. More importantly, it has improved the
Fund's access to capital and its ability to pursue large acquisition
opportunities.

Enerplus also has numerous internal development opportunities on existing
properties, including low risk development drilling, the application of
waterflood technology, and application of incremental recovery techniques
designed to increase production and improve reservoir recoveries. In particular,
Enerplus has a large inventory of low-cost shallow gas drilling opportunities
that can be activated quickly in the event of a recovery in natural gas prices.

As Enerplus distributes much of its net cash flow, its ability to replace
production and grow Unitholder value depends on its success in acquiring new
reserves. Although Enerplus bid on numerous asset and corporate packages
throughout 2001, the Fund was largely unsuccessful due to its disciplined
acquisition criteria. With the recent decline in commodity prices, the desire or
need of many E&P companies to strengthen their balance sheets, and the asset
rationalization that typically follows a period of industry consolidation, we
expect that 2002 will bring better opportunities to acquire quality properties
at more reasonable prices.

FORWARD-LOOKING STATEMENTS

This discussion and analysis contains forward-looking statements relating to
future events or future performance. In some cases, forward-looking statements
can be identified by terminology such as "may", "will", "should", "expects",
"projects", "plans", "anticipates" and similar expressions. These statements
represent management's expectations or beliefs concerning, among other things,
future operating results and various components thereof or the economic
performance of Enerplus. The projections, estimates and beliefs contained in
such forward-looking statements necessarily involve known and unknown risks and
uncertainties, including the business risks discussed above, which may cause
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. Accordingly, readers are cautioned that events
or circumstances could cause results to differ materially from those predicted.

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