Exhibit 1

RENEWAL ANNUAL INFORMATION FORM

For the year ended December 31, 2003

April 22, 2004

TABLE OF CONTENTS

i

ii

GLOSSARY OF TERMS

Unless the context otherwise requires, in this Annual Information Form, the following terms and abbreviations have the meanings set forth below.  Additional terms relating to oil and natural gas reserves and operations have the meanings set forth under “Presentation of Enerplus’ Oil and Gas Reserves and Production Information.”

“EGEM” means Enerplus Global Energy Management Company, an indirect wholly owned subsidiary of the Fund which, prior to its acquisition by Enerplus from a third party, provided management and administrative services to Enerplus;

“EnerMark” means EnerMark Inc., a corporation organized under the Business Corporations Act (Alberta) and a wholly owned subsidiary of the Fund;

“Enerplus” means Enerplus Resources Fund and its subsidiaries, taken as a whole;

“EOG” means Enerplus Oil & Gas Ltd., a corporation organized under the Business Corporations Act (Alberta) and a wholly owned subsidiary of ERC;

“ERC” means Enerplus Resources Corporation, a corporation organized under the Business Corporations Act (Alberta) and a wholly owned subsidiary of EnerMark;

“Fund” means Enerplus Resources Fund;

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

“Sproule” means Sproule Associates Limited, independent petroleum consultants;

“Sproule Report” means the independent engineering evaluations of Enerplus’ oil, NGLs and natural gas interests prepared by Sproule dated March 19, 2004 and effective January 1, 2004, utilizing commodity price forecasts of Sproule dated January 1, 2004;

“Tax Act” means the Income Tax Act (Canada);

“Trust Indenture” means the Amended and Restated Trust Indenture dated January 1, 2004 among EnerMark, ERC and the Trustee, as may be amended, supplemented or restated from time to time;

“Trust Units” means the trust units of the Fund, each representing an equal undivided beneficial interest in the Fund; and

“Trustee” means CIBC Mellon Trust Company, or its successor as trustee of the Fund.

iii

ABBREVIATIONS AND CONVERSIONS

In this Annual Information Form, the following abbreviations have the meanings set forth below.

AECO	Alberta Energy Company interconnect with the Nova System, the Canadian benchmark for natural gas pricing purposes
bbls	barrels, with each barrel representing 34.972 Imperial gallons or 42 U.S. gallons
bbls/d	barrels per day
Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
BOE	barrels of oil equivalent converting 6 Mcf of natural gas to one barrel of oil equivalent and one barrel of natural gas liquids to one barrel of oil equivalent. The factor used to convert natural gas and natural gas liquids to oil equivalent is not based on either energy content or prices but is a commonly used industry benchmark.
BOE/d	barrels of oil equivalent per day
GJ	gigajoules
Mbbls	one thousand barrels
MBOE	one thousand barrels of oil equivalent
Mcf	one thousand cubic feet
Mcf/d	one thousand cubic feet per day
MMbbls	one million barrels
MMBOE	one million barrels of oil equivalent
MMBTU	one million British Thermal Units
MMcf	one million cubic feet
MMcf/d	one million cubic feet per day
MW	megawatts of electricity
NGLs	natural gas liquids
WTI	West Texas Intermediate at Cushing, Oklahoma, the benchmark for North American crude oil pricing purposes

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

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

To Convert From	To	Multiply By
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	0.4047
hectares	acres	2.471

iv

PRESENTATION OF ENERPLUS’
OIL AND GAS RESERVES AND PRODUCTION INFORMATION

Disclosure of Information

In this Annual Information Form, all estimates of oil and natural gas reserves and production are presented on a “company interest” (as defined below) basis, unless indicated that they have been presented on a “gross” or “net” basis. Enerplus’ actual oil and natural gas reserves and future production will be greater than or less than the estimates provided in this Annual Information Form.  The estimated future net revenue from the production of Enerplus’ oil and natural gas reserves do not represent the fair market value of Enerplus’ reserves.

The United States Securities and Exchange Commission (the “SEC”) generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves net of royalties and interests of others that an issuer has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.  Canadian securities laws permit oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves (each as defined below), and to disclose reserves and production on a “gross” basis before deducting royalties.  Probable Reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than Proved Reserves. Enerplus has prepared this Annual Information Form in accordance with Canadian disclosure requirements, and as a result, Enerplus has disclosed reserves designated as “Probable Reserves” and “Proved plus Probable Reserves.”  The SEC’s guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements.  Moreover, Enerplus has determined and disclosed estimated future net cash flow from its reserves using both constant and forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report.

Although the Sproule Report is effective January 1, 2004, Sproule has confirmed that the information contained in the Sproule Report would be identical if it were presented effective December 31, 2003, the fiscal year-end of the Fund. As a result, throughout this Annual Information Form, an effective date of December 31, 2003 has been utilized so that the effective date of Enerplus’ oil and gas reserves information coincides with the Fund’s fiscal year-end as contemplated in NI 51-101.

Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs.  BOEs may be misleading, particularly if used in isolation.  A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Note to Reader Regarding Oil and Gas Information and National Instrument 51-101

The oil and gas operational and reserves information contained in this Annual Information Form contains the information required to be included in the Statement of Reserves Data and Other Oil and Gas Information pursuant to NI 51-101 adopted by the Canadian securities regulatory authorities and has been prepared and prescribed in accordance with Form 51-101F1.  Readers should also refer to the Report on Reserves Data by Sproule Associates Limited attached hereto as Exhibit “A” and the Report of Management and Directors on Oil and Gas Disclosure attached hereto as Exhibit “B”.  The effective date for the Statement of Reserves Data and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2003 and the information contained in the Annual Information Form has been prepared as of April 22, 2004.

Certain of the following definitions and guidelines are contained in Section 5.4 of Volume 1 of the Canadian Oil and Gas Evaluation Handbook (First Edition, June 30, 2002) prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the “COGE Handbook”) and have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society).  Readers should consult the COGE Handbook for additional explanation and guidance.  Certain other terms used in this Annual Information Form have the meanings assigned to them in NI 51-101 and accompanying Companion Policy 51-101CP, adopted by the Canadian securities regulatory authorities.

v

Interests in Reserves, Production, Wells and Properties

“company interest” means, in relation to Enerplus’ interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and including any royalty interests of Enerplus.

“gross” means:

(i)in relation to Enerplus’ interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Enerplus;

(ii)in relation to wells, the total number of wells in which Enerplus has an interest; and

(iii)in relation to properties, the total area of properties in which Enerplus has an interest.

“net” means:

(i)in relation to Enerplus’ interest in production or reserves, its working interest (operating or non-operating) share after deduction of royalty obligations, plus Enerplus’ royalty interests in those production or reserves;

(ii)in relation to Enerplus’ interest in wells, the number of wells obtained by aggregating Enerplus’ working interest in each of its gross wells; and

(iii)in relation to Enerplus’ interest in a property, the total area in which Enerplus has an interest multiplied by the working interest owned by Enerplus.

“working interest” means the percentage of undivided interest held by Enerplus in the oil and/or natural gas or mineral lease granted by the mineral owner, Crown or freehold, which interest gives Enerplus the right to “work” the property (lease) to explore for, develop, produce and market the leased substances.

Reserves Categories

“Proved Reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves.

“Probable Reserves” are those additional reserves that are less certain to be recovered than Proved Reserves.  It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves.

“Possible Reserves” are those additional reserves that are less certain to be recovered than Probable Reserves.  It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible Reserves.

Development and Production Status

Each of the reserves categories (Proved, Probable and Possible) may be divided into developed and undeveloped categories:

“Developed Reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production.  The developed category may be subdivided into Producing and Non-Producing.

vi

•“Developed Producing Reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

•“Developed Non-Producing Reserves” are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

“Undeveloped Reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (Proved, Probable, Possible) to which they are assigned.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest-level sum of individual entity estimates for which reserves estimates are presented).  Reported reserves should target the following levels of certainty under a specific set of economic conditions:

•at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves;

•at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves; and

•at least a 10 percent probability that the quantities actually recovered will equal the sum of the estimated Proved plus Probable plus Possible Reserves.

Description of Price and Cost Assumptions

“Constant prices and costs” means prices and costs used in an estimate that are:

(i)Enerplus’ prices and costs as at December 31, 2003, held constant throughout the estimated lives of the properties to which the estimate applies; and

(ii)if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Enerplus is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices or costs referred to in paragraph (i).

“Forecast prices and costs” means future prices and costs that are:

(i)generally accepted as being a reasonable outlook of the future; and

(ii)if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Enerplus is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices or costs referred to in paragraph (i).

Calculation of Reserve Life Index

“Reserve Life Index” means the amount obtained by dividing the quantity of a particular category of reserves by Sproule’s forecast of the first year’s production for the corresponding reserve category.

vii

PRESENTATION OF ENERPLUS’ FINANCIAL INFORMATION

The financial information included and incorporated by reference in this Annual Information Form has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Canadian GAAP differs in some significant respects from U.S. GAAP and therefore this financial information may not be comparable to the financial information of U.S. companies.  The principal differences as they apply to the Fund are summarized in Note 12 to the Fund’s audited consolidated financial statements for the year ended December 31, 2003.

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

DESCRIPTION OF DISTRIBUTABLE INCOME

Throughout this Annual Information Form, Enerplus uses the term “distributable income” to refer to the amount of cash that has been or is to be available for distribution to the Fund’s unitholders.  “Distributable income” is not a measure recognized by Canadian generally accepted accounting principles (“GAAP”) and does not have a standardized meaning prescribed by GAAP, but is an amount calculated in accordance with the terms of the Fund’s Trust Indenture.  Therefore, distributable income of the Fund may not be comparable to similar measures presented by other issuers, and investors are cautioned that distributable income should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements which are based on Enerplus’ current internal expectations, estimates, projections, assumptions and beliefs.  Forward-looking statements are made by Enerplus in light of its experience and its perception of historical trends.

All statements that address expectations or projections about the future, including statements about Enerplus’ strategy for growth, expected future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future contractual commitments, are forward-looking statements.  Some of the forward-looking statements may be identified by words such as “expects”, “anticipates”, “believes”, “projects”, “plans” and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties. Such forward-looking statements necessarily involve known and unknown risks and uncertainties, which may cause Enerplus’ actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements.

These risks and uncertainties include, among other things, changes in general economic, market and business conditions; changes or fluctuations in production levels, commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation, investment eligibility or investment criteria; Enerplus’ ability to comply with current and future environmental or other laws; Enerplus’ success at acquisition, exploitation and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; and the occurrence of unexpected events involved in the operation and development of oil and gas properties.  The foregoing factors are not exhaustive.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in Enerplus’ Management’s Discussion and Analysis, incorporated by reference herein.  Readers are also referred to the risk factors described in this Annual Information Form and in other documents Enerplus files from time to time with securities regulatory authorities.  Copies of these documents are available without charge from Enerplus.  Enerplus disclaims any responsibility to update these forward-looking statements.

viii

ENERPLUS RESOURCES FUND

Renewal Annual Information Form
For the year ended December 31, 2003

STRUCTURE OF ENERPLUS RESOURCES FUND

Enerplus Resources Fund

Enerplus Resources Fund is an energy investment trust created in 1986 under the laws of the Province of Alberta pursuant to the Trust Indenture.  The Fund’s assets currently consist of the securities of several direct and indirect operating subsidiaries (the primary of which are EnerMark, ERC and EOG), an unsecured note issued by EnerMark to the Fund and 95%, 99% and 99% royalties on the crude oil and natural gas property interests of EnerMark, ERC and EOG, respectively.  The head, principal and registered office of Enerplus is located at The Dome Tower, Suite 3000, 333 - 7^th Avenue S.W., Calgary, Alberta, T2P 2Z1.  The Trustee of the Fund is CIBC Mellon Trust Company located at 600 The Dome Tower, 333 – 7^th Avenue S.W., Calgary, Alberta T2P 2Z1.

The Fund’s primary focus is to maintain and enhance cash distributions to its unitholders through the development of its operating subsidiaries’ existing crude oil and natural gas properties, the acquisition of new producing properties and the monetization, by the way of sale or farm out, of its operating subsidiaries’ higher risk exploration opportunities.  Development efforts are concentrated on optimizing production from existing and new crude oil and natural gas reserves.

EnerMark Inc., Enerplus Resources Corporation and Enerplus Oil & Gas Ltd.

Each of EnerMark, ERC and EOG are corporations organized under the Business Corporations Act (Alberta).  All of the issued and outstanding common shares of EnerMark are owned by the Fund, all of the issued and outstanding common shares of ERC are owned by EnerMark and all of the issued and outstanding common shares of EOG are owned by ERC.The board of directors of EnerMark is responsible for the governance of Enerplus.

EnerMark, ERC and EOG, together with the Fund’s other direct and indirect operating subsidiaries, acquire, exploit and operate crude oil and natural gas assets in western Canada for the benefit of the Fund.  See “Operational Information” and “Oil and Natural Gas Reserves” for information regarding the operations and oil and natural gas reserves of Enerplus.

1

Organization Chart

The simplified organizational structure of Enerplus, including the material subsidiaries of the Fund and the flows of cash from EnerMark, ERC and EOG to the Fund and from the Fund to its unitholders, is set forth below:

2

GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND

Historical Overview

Enerplus was formed in 1986 and was historically one of a group of royalty trusts, income funds and other entities managed by companies within the Enerplus organization.  In recent years, Enerplus Resources Fund has grown significantly as a result of consolidation of many of those entities, as discussed below, and a series of corporate and asset acquisitions.

Merger with Westrock Energy Income Fund I and Westrock Energy Income Fund II

On June 8, 2000, Enerplus, Westrock Energy Income Fund I (“Westrock I”) and Westrock Energy Income Fund II (“Westrock II”) merged and continued as “Enerplus Resources Fund”.  Enerplus, Westrock I and Westrock II were managed by affiliated management companies which were part of the Enerplus organization (and each of which was a predecessor of EGEM).  The transaction was negotiated on an arm’s length basis on behalf of each of Enerplus, Westrock I and Westrock II by independent special committees of the boards of directors responsible for each entity.

Affiliation with El Paso Corporation

On August 3, 2000, an indirect wholly-owned subsidiary of El Paso Corporation (“El Paso”) of Houston, Texas acquired the companies responsible for the management of various public and private funds within the Enerplus organization, including EGEM.  On April 23, 2003, Enerplus acquired EGEM from El Paso, which resulted in the termination of this affiliation, as described under “- Management Internalization Transaction” below.

Listing on the New York Stock Exchange

On November 17, 2000, the Trust Units were listed and posted for trading on the New York Stock Exchange (the “NYSE”) under the trading symbol “ERF”.  Enerplus was the first Canadian royalty trust to have its securities trade on the NYSE.

Merger with EnerMark Income Fund

On June 21, 2001, Enerplus and EnerMark Income Fund merged and continued as “Enerplus Resources Fund”.  Enerplus and EnerMark Income Fund were managed by affiliated management companies which were part of the Enerplus Group of Companies.  Although it was concluded that the merger was not subject to the provisions governing “related party transactions” within the meaning of certain Canadian securities laws, due to the common management of the two funds, the Merger was effectively treated as a related party transaction by the funds and their respective boards in order to avoid the perception of any conflict of interest or any informational disadvantage arising from the merger, including complying with certain valuation, disclosure and minority approval requirements.  The transaction was negotiated on an arm’s length basis on behalf of Enerplus and EnerMark Income Fund by independent special committees of the boards responsible for each entity.

EnerMark Income Fund was created on April 3, 1996 as a result of a corporate reorganization of Mark Resources Inc. by way of a plan of arrangement.  From 1997 through 2000, EnerMark Income Fund made several corporate and asset acquisitions, including the acquisitions of Quest Oil & Gas Inc. in 1997, Derrick Energy Corporation in 1999 and Western Star Exploration Ltd., Pursuit Resources Corp., EBOC Energy Ltd. and Cabre Exploration Ltd., in addition to a significant asset acquisition in the Hanna, Alberta area in 2000.

Acquisition of Celsius Energy Resources Ltd.

On October 21, 2002, Enerplus acquired all of the outstanding shares of Celsius Energy Resources Ltd. (“Celsius”), a private oil and gas producer based in Calgary, Alberta, which was a wholly owned Canadian subsidiary of U.S.-based Questar Market Resources Inc., for total consideration of $161.4 million, after working capital adjustments.  On October 22, 2002, Celsius was amalgamated with EnerMark.

3

Acquisition of PCC Energy Inc. and PCC Energy Corp.

On March 5, 2003, Enerplus acquired all of the outstanding shares of PCC Energy Inc. and PCC Energy Corp. (collectively, “PCC”), which were wholly owned Canadian subsidiaries of U.S.-based PetroCorp Incorporated, for total cash consideration of $167.6 million, before final working capital adjustments and costs of the acquisition.  A portion of the PCC properties acquired are subject to a royalty arrangement structured as a net profits interest (“NPI”) with a private U.S. company. The NPI is accounted for as a working interest of the U.S. company in these properties and as a result is not included in Enerplus’ reserves, production, or financial information.

Management Internalization Transaction

On April 23, 2003, following receipt of unitholder approval, Enerplus acquired all of the outstanding shares of EGEM from an indirect wholly owned subsidiary of El Paso and incurred associated costs for a total cash consideration of $55.1 million. Prior to the acquisition, EGEM received management fees from Enerplus for providing administrative and management services to the Fund and its operating subsidiaries pursuant to a management agreement.  As part of this transaction, EGEM agreed to fix the total fees payable under the management agreement from January 1, 2003 to April 23, 2003 at $3.2 million.  Immediately following completion of the transaction, EGEM assigned and transferred all of its rights and obligations under the management agreement to EnerMark (a wholly owned subsidiary of the Fund), and the management agreement was effectively terminated.

2003 Acquisition and Disposition Activity

Enerplus continually pursues and evaluates potential acquisitions of oil and natural gas properties, companies, trusts and other energy-related assets as part of its ongoing acquisition program.  Acquisition activities during 2003 (which includes the above-described PCC acquisition but excludes the Ice Energy acquisition described below) added approximately 5,595 BOE/d of production and 28.1 MMBOE of Proved plus Probable Reserves to Enerplus at an aggregate cost of $225.3 million.

Enerplus routinely evaluates its property portfolio and disposes of properties that are viewed as higher-risk, non-core holdings.  In 2003, Enerplus divested $73.2 million of non-core properties that produced approximately 3,033 BOE/d and contained 9.2 MMBOE of Proved plus Probable Reserves.

Recent Developments Since Fiscal Year-End

Non-Resident Ownership, Mutual Fund Trust Status and Impact of 2004 Canadian Federal Government Budget Proposals

Since its listing on the New York Stock Exchange in November of 2000, Enerplus has seen increased interest in its Trust Units, both in terms of trading volumes and level of ownership, by persons who are not residents of Canada.  Based on the most recent information obtained by Enerplus through its transfer agent and financial intermediaries in February 2004,an estimated 64% of the issued and outstanding Trust Units were held by non-residents of Canada at that time.  As a result of the current structure and assets of the Fund, Enerplus meets the “mutual fund trust” status requirements under the Tax Act by reason of an exception to certain provisions within the Tax Act which would otherwise restrict non-resident ownership of the units of a mutual fund trust. The Fund’s Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents. However, on March 23, 2004 the Canadian federal government tabled its budget which proposed certain amendments to the Tax Act which, if implemented in their present form, would affect Canadian mutual fund trusts. In particular, one proposed amendment would effectively eliminate, over a period of time, the exception currently relied on by Enerplus regarding non-resident ownership restrictions and require the Fund to comply with the requirement that it “not be maintained primarily for the benefit of non-residents” before January 1, 2007.  If the proposed amendment is enacted, Enerplus intends to comply with the requirements to maintain its mutual fund trust status.  Enerplus is reviewing various alternatives to mitigate the impact of this legislation as it is currently proposed.  Enerplus has in excess of two and one-half years to pursue and implement strategies in this regard.

4

Enerplus intends to continue to take the necessary measures in order to ensure the Fund continues to qualify as a mutual fund trust under the Tax Act. Enerplus has not currently implemented any non-resident ownership or trading restrictions. However, the Fund’s Trust Indenture includes provisions that allow the board of directors of EnerMark to adopt non-resident ownership constraints if required in order to ensure that the Fund maintains its mutual fund trust status. See “Information Respecting Enerplus Resources Fund - Description of the Trust Units and the Trust Indenture – Non-Resident Ownership Provisions”.  Should such a situation occur and Enerplus is unsuccessful in mitigating these circumstances, the directors could impose a specific limit on the number of Trust Units that could be beneficially owned by non-residents of Canada, similar to the non-resident ownership restrictions in place for other income funds and royalty trusts in Canada.  Steps could be taken to ensure that no additional Trust Units are issued or transferred to non-residents, including limiting or suspending the trading of the Trust Units on the New York Stock Exchange.  If it is necessary to reduce the level of non-resident ownership below a certain level, non-residents (generally chosen in the inverse order of acquisition or registration of the Trust Units) may be required to sell all or a portion of their Trust Units.  In these circumstances, the Trust Units would continue to trade on the Toronto Stock Exchange and non-residents of Canada would continue to be able to sell their Trust Units on that Exchange.  There can be no assurance that such circumstances would not detrimentally affect the market price of the Trust Units. For additional information regarding these matters, including the consequences if the Fund lost its mutual fund trust status, see “Risk Factors - Changes in tax and other laws may adversely affect unitholders” and “Risk Factors - There would be material adverse consequences if the Fund lost its status as a mutual fund trust under Canadian tax laws” in this Annual Information Form.

Another proposal contained in the Canadian federal government’s 2004 budget would affect the taxation of distributions to non-resident unitholders. An estimated 15% of the Fund’s current distributions to non-resident unitholders are deemed to be a return of capital, which are not subject to Canadian withholding tax.  It has been proposed that a Canadian withholding tax be applied to the return of capital portion of distributions made after 2004 to non-resident investors.  Under this proposal, the tax, at a rate of 15%, would be withheld from the distributions at source.

The budget also introduces an amendment to limit the level of investment by pension funds in business income trusts after 2004.  This should not impact Enerplus, as it is not currently considered a business income trust for the purposes of these rules.

Acquisition of Ice Energy Limited

On January 7, 2004, Enerplus completed the acquisition of all of the issued and outstanding shares of Ice Energy Limited (“Ice Energy”).  Enerplus previously owned approximately 12.7% of the shares of Ice Energy which were acquired in a prior transaction.  The total purchase price for the all of the Ice Energy shares, including those previously owned by Enerplus, was approximately $132.2 million.

Ice Energy was a non-public oil and natural gas company focused on shallow natural gas development in Alberta and Saskatchewan.  Ice Energy’s production at the time the transaction was completed was approximately 2,300 BOE/d, comprised almost entirely of natural gas. Enerplus’ internal engineering estimates attributed 13.9 MMBOE of Proved plus Probable Reserves to Ice Energy at November 1, 2003, comprised of 80,034 MMcf of natural gas and 516 Mbbls of crude oil and NGLs.  Also included in the acquisition were 72,500 net acres of undeveloped land.

As a result of this acquisition, Enerplus acquired an interest in the Shackleton area of western Saskatchewan, which Enerplus believes has long-term natural gas development potential.  The acquired interests also include a 50% working interest in a joint venture to develop a commercial coal bed methane (also known as natural gas from coal) project in central Alberta.

The oil and natural gas reserves of Ice Energy acquired by Enerplus are not included in Enerplus’ reserve information under the heading “Oil and Natural Gas Reserves”, and the production and other operational information attributable to the acquired Ice Energy properties has been included in Enerplus’ results since January 7, 2004 but is not included in the information contained in this Annual Information Form as the transaction was completed in 2004.

5

Joslyn Creek Oil Sands SAGD Development

Enerplus is positioned to participate in the future development of Canada’s oil sands reserves through its ownership of a 16% working interest in Oil Sands Lease #24 (“Joslyn Creek”) acquired in 2002 for approximately $16.4 million. Located in the Athabasca Oil Sands fairway of northeastern Alberta near other significant oil sands projects, Joslyn Creek has both steam-assisted gravity drainage (“SAGD”) and mining potential. To date, several hundred core holes have been drilled and evaluated on the lease to quantify the resource potential. Based on the results of this initial evaluation, Enerplus and its working interest partners in Joslyn Creek are pursuing a pilot SAGD project on the lease. Phase one of the SAGD commercial project is currently being completed and is expected to produce 600 bbls/d. Enerplus expects initial production from this phase to occur in the second quarter of 2004 with peak production expected in 2005.  Following the pilot project, Enerplus currently anticipates pursuing a full-scale 10,000 bbl/d project to be completed and producing by 2007.

On April 1, 2004, the operator of the project announced the results of certain reserves and resource studies on the Joslyn Creek project. The studies confirmed the presence of significant quantities of commercially recoverable bitumen on the project.  An independent reserves evaluation effective December 31, 2003 conducted in accordance with NI 51-101 attributed 298 MMBOE of gross Probable Reserves to the SAGD portion of the Joslyn Creek project, which would result in 47.6 MMBOE of gross Probable Reserves being attributed to Enerplus’ 16% working interest in the project.  Enerplus did not include any SAGD reserves from the Joslyn Creek project in its 2003 year-end reserves described under “Oil and Natural Gas Reserves”. Enerplus currently intends to include these reserves in its 2004 year-end reserves evaluation pending a review of the 2004 results of the first phase of the SAGD pilot project.

6

OIL AND NATURAL GAS RESERVES

Enerplus’ reserves have been evaluated in accordance with NI 51-101. Sproule Associates Limited, a firm of independent petroleum engineers, has evaluated crude oil and natural gas properties which comprise approximately 87% of Enerplus’ Proved Developed Producing crude oil and natural gas reserves value discounted at 10%, and 86% of Enerplus’ Proved plus Probable oil and natural gas reserves value discounted at 10%. Enerplus has evaluated the balance of the properties using similar evaluation parameters, including the same forecast price and cost assumptions utilized by Sproule. Sproule has reviewed Enerplus’ evaluation of these properties.

In preparing its report, Sproule obtained basic information from Enerplus, which included production and land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans.  Other engineering, geological or economic data required to conduct the evaluation and upon which the Sproule Report is based, was obtained from public records, other operators and from Sproule’s non-confidential files.  Information concerning the extent and character of ownership of Enerplus’ interests and the accuracy of all factual data supplied to Sproule by third parties was accepted by Sproule as represented and neither title searches nor field inspections were conducted.

Enerplus follows the Canadian practice of reporting company interest and gross production and reserve volumes, which are presented prior to the deduction of royalties and similar payments.  In the United States, production and reserve volumes are reported on a net basis, after deducting these amounts.  The Canadian practice of using forecast prices and costs when estimating the quantities of reserves is also followed by Enerplus.  In the United States, reserve estimates are calculated using prices and costs held constant at amounts in effect at the date of the reserve report.  Enerplus also follows the Canadian practice of reporting the aggregate of Proved plus Probable reserves portion.  As a consequence, Enerplus’ production volumes and reserve estimates may not be comparable to those made by companies utilizing United States disclosure standards.

The following is a summary, as at December 31, 2003 of Enerplus’ crude oil, NGLs and natural gas reserves and the estimated net present values of future net cash revenues associated with such reserves, based on forecast and constant price and cost assumptions. The following reserves information does not include any reserve volumes or values attributed to Ice Energy Limited (acquired by Enerplus in early January 2004) or Enerplus’ interest in the Joslyn Creek oil sands project.The tables summarize the data contained in the evaluations and as a result may contain slightly different numbers than the evaluations due to rounding. Additionally, the numbers in the tables may not add due to rounding.

All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties and estimated future capital expenditures. Future net revenues have been presented on the basis that no income taxes will be paid by Enerplus in the future and therefore after-tax future net revenues from Enerplus’ oil and gas reserves are equal to the before-tax future net revenues. See “Operational Information – Tax Horizon”. It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of Enerplus’ crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in “Presentation of Enerplus’ Oil and Gas Reserves and Production Information” in conjunction with the following tables and notes.

7

Summary of Oil and Gas Reserves
and Net Present Values of Future Net Revenue
As of December 31, 2003

Forecast Prices and Costs

	OIL AND GAS RESERVES
	LIGHT AND MEDIUM OIL			HEAVY OIL			NATURAL GAS
RESERVES CATEGORY	Company Interest	Gross	Net	Company Interest	Gross	Net	Company Interest	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Bcf)	(Bcf)	(Bcf)
Proved Reserves
Proved Developed Producing	64,288	63,570	58,596	21,571	21,524	18,802	737	730	580
Proved Developed Non-Producing	97	97	87	63	63	51	26	26	20
Proved Undeveloped	1,388	1,348	1,065	3,656	3,656	3,003	104	103	84
Total Proved Reserves	65,773	65,015	59,748	25,290	25,242	21,857	867	859	684
Probable Reserves	20,342	20,114	17,696	7,465	7,446	6,474	284	281	230
Total Proved Plus Probable Reserves	86,115	85,129	77,444	32,755	32,688	28,331	1,151	1,140	914

	OIL AND GAS RESERVES
	NATURAL GAS LIQUIDS			TOTAL
RESERVES CATEGORY	Company Interest	Gross	Net	Company Interest	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(MBOE)	(MBOE)	(MBOE)
Proved Reserves
Proved Developed Producing	11,846	11,696	8,254	220,605	218,457	182,370
Proved Developed Non-Producing	517	515	360	5,061	5,059	3,850
Proved Undeveloped	1,208	1,200	850	23,502	23,371	18,885
Total Proved Reserves	13,571	13,412	9,464	249,168	246,887	205,085
Probable Reserves	3,742	3,689	2,624	78,898	78,031	65,045
Total Proved Plus Probable Reserves	17,313	17,101	12,088	328,066	324,918	270,130

	NET PRESENT VALUES OF FUTURE NET REVENUE
	BEFORE AND AFTER INCOME TAXES,
RESERVES CATEGORY	DISCOUNTED AT (%/YEAR)
	0%	5%	10%	15%	20%
	(in $ millions)
Proved Reserves
Proved Developed Producing	3,563	2,277	1,727	1,420	1,222
Proved Developed Non-Producing	82	56	43	35	29
Proved Undeveloped	286	172	111	75	51
Total Proved Reserves	3,930	2,505	1,882	1,530	1,302
Probable Reserves	1,305	602	361	250	188
Total Proved Plus Probable Reserves	5,235	3,107	2,242	1,780	1,490

8

Summary of Oil and Gas Reserves
and Net Present Values of Future Net Revenue
As of December 31, 2003

Constant Prices and Costs

	OIL AND GAS RESERVES
	LIGHT AND MEDIUM OIL			HEAVY OIL			NATURAL GAS
RESERVES CATEGORY	Company Interest	Gross	Net	Company Interest	Gross	Net	Company Interest	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Bcf)	(Bcf)	(Bcf)
Proved Reserves
Proved Developed Producing	66,522	65,805	60,466	22,115	22,068	19,202	744	736	585
Proved Developed Non-Producing	99	99	88	59	59	48	26	26	20
Proved Undeveloped	1,398	1,358	1,059	3,707	3,707	3,018	104	104	84
Total Proved Reserves	68,019	67,263	61,613	25,883	25,836	22,267	874	866	690
Probable Reserves	20,945	20,714	18,156	7,698	7,678	6,657	286	282	231
Total Proved Plus Probable Reserves	88,964	87,977	79,769	33,581	33,514	28,924	1,160	1,148	921

	OIL AND GAS RESERVES
	NATURAL GAS LIQUIDS			TOTAL
RESERVES CATEGORY	Company Interest	Gross	Net	Company Interest	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(MBOE)	(MBOE)	(MBOE)
Proved Reserves
Proved Developed Producing	11,986	11,836	8,328	224,623	222,376	185,496
Proved Developed Non-Producing	518	516	360	5,012	5,010	3,995
Proved Undeveloped	1,209	1,201	850	23,647	23,599	18,927
Total Proved Reserves	13,713	13,553	9,538	253,282	250,985	208,418
Probable Reserves	3,757	3,705	2,627	80,066	79,097	65,940
Total Proved Plus Probable Reserves	17,470	17,258	12,165	333,348	330,082	274,358

	NET PRESENT VALUES OF FUTURE NET REVENUE
	BEFORE AND AFTER INCOME TAXES,
RESERVES CATEGORY	DISCOUNTED AT (%/YEAR)
	0%	5%	10%	15%	20%
	(in $ millions)
Proved Reserves
Proved Developed Producing	4,035	2,652	2,021	1,657	1,417
Proved Developed Non-Producing	93	66	50	41	35
Proved Undeveloped	349	221	150	107	77
Total Proved Reserves	4,477	2,938	2,222	1,805	1,529
Probable Reserves	1,387	678	421	297	226
Total Proved Plus Probable Reserves	5,864	3,616	2,643	2,102	1,756

9

Notes:

(1)The estimated net present values of future net revenue include the Alberta Royalty Tax Credit based on current legislation in place on December 31, 2003.

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

(3)Prices for oil F.O.B. Edmonton are based upon 40º API oil having less than 0.4% sulphur.  Prices for natural gas are based upon a base pressure of 14.65 pounds per square inch and base temperature of 60ºF.  The wellhead oil prices were adjusted for quality and transportation to reflect the actual price to be received.  The natural gas price adjusted, where necessary, only for heating values and the differing costs of service applied by various purchasers.  The natural gas liquids prices were adjusted to reflect current prices received.

(4)The forecast price and cost case assumes the continuance of current laws and regulations, and any increase in selling prices also takes inflation into account.  The estimated future net revenue to be received from the production of the reserves was based on an inflation rate of 1.5% per year, an exchange rate of Cdn$1.00=US$0.75 and the following price forecasts supplied by Sproule:

	CRUDE OIL										NATURAL GAS LIQUIDS
Year	WTI Cushing Oklahoma		Edmonton Par Price 40° API		Hardisty Heavy 12° API		Cromer Medium 29.3° API		NATURAL GAS AECO Gas Price		Edmonton Par Price
											Propanes		Butanes		Pentanes Plus
	($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/MMBTU)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)
2004	29.63		37.99		23.80		32.99		5.81		28.04		31.15		38.91
2005	26.80		34.24		21.28		29.44		5.15		22.56		25.52		35.07
2006	25.76		32.87		20.80		28.47		4.59		20.58		23.28		33.67
2007	26.14		33.37		21.33		29.07		4.71		20.89		23.63		34.17
2008	26.53		33.87		21.84		29.54		4.80		21.20		23.98		34.69
Thereafter	+1.5	%	+1.5	%	+1.5	%	+1.5	%	+1.5	%	+1.5	%	+1.5	%	+1.5	%

(5)The constant price and cost case assumes the continuance of product prices at December 31, 2003 and operating costs projected for 2004, and the continuance of current laws and regulations.  Product prices have not been escalated beyond this date nor have operating and capital costs been increased on an inflationary basis.  The future net revenue to be received from the production of the reserves was based on an exchange rate of Cdn$1.00=US$0.77 and the following prices:

CRUDE OIL					NATURAL GAS LIQUIDS
WTI Cushing Oklahoma	Edmonton Par Price 40° API	Hardisty Heavy 12° API	Cromer Medium 29.3° API	NATURAL GAS AECO Gas Price	FOB Field Gate
					Propanes	Butanes	Pentanes Plus
($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/MMBTU)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)
32.52	40.41	29.52	36.68	5.45	27.66	35.77	41.58

(6)The undiscounted total future net revenue by reserves category as of December 31, 2003, using both constant and forecast prices and costs, is set forth below:

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Other Costs	Future Net Revenue
	(in $ millions)
Constant Prices and Costs
Proved Reserves	8,513	1,519	2,242	178	91	6	4,477
Proved Plus Probable Reserves	11,178	1,997	2,988	213	93	22	5,865
Forecast Prices and Costs
Proved Reserves	8,249	1,383	2,625	181	125	5	3,930
Proved Plus Probable Reserves	11,144	1,860	3,666	216	142	24	5,236

10

(7)The net present value of future net revenue by reserves category and production group as of December 31, 2003, using both constant and forecast prices and costs and discounted at 10% per year, is set forth below:

		Future Net Revenue Before and After Income Taxes (Discounted at 10%/year)
Reserves Category	Production Group	Constant Prices and Costs	Forecast Prices and Costs
		(in $ millions)
Proved Reserves	Light and Medium Crude Oil(a)	542	407
	Heavy Oil	177	128
	Natural Gas(b)	1,503	1,347
Proved Plus Probable Reserves	Light and Medium Crude Oil(a)	636	480
	Heavy Oil	214	158
	Natural Gas(b)	1,793	1,604

(a)Includes solution gas and other by-products.

(b)Includes by-products by excludes solution gas from oil wells.

(8)The volume of gross Proved plus Probableproduction estimated by Sproule for 2004 in preparing the estimated net present values of future net revenue is as follows.

Product Type	Aggregate Estimated 2004 Production	Daily Estimated 2004 Production
Crude oil
Light and medium crude oil	6,030 Mbbls	16,475 bbls/d
Heavy oil	2,010 Mbbls	5,492 bbls/d
Total crude oil	8,040 Mbbls	21,967 bbls/d
Natural gas liquids	1,663 Mbbls	4,554 bbls/d
Total liquids	9,703 Mbbls	26,511 bbls/d
Natural gas	89,900 MMcf	245,628 Mcf/d
Total	24,686 MBOE	67,449 BOE/d

(9)The amount of development costs deducted in the estimation of net present value of future net revenue is as follows (see also “Operational Information – Development Activities”):

	Constant Prices and Costs				Forecast Prices and Costs
	Proved Reserves		Proved Plus Probable Reserves		Proved Reserves		Proved Plus Probable Reserves
Year	Undiscounted	Discounted at 10%/year	Undiscounted	Discounted at 10%/year	Undiscounted	Discounted at 10%/year	Undiscounted	Discounted at 10%/year
	(in $ millions)
2004	100	95	116	110	100	95	116	110
2005	41	36	42	37	42	36	43	37
2006	17	13	25	20	17	13	26	20
2007	7	5	12	9	8	5	12	8
2008	6	4	10	7	6	4	11	7
Remainder	7	4	8	2	8	5	8	6
Total	178	157	213	185	181	158	216	188

(10)Enerplus has approximately 7,436 MBOE of Proved plus Probable Reserves which are capable of production but which, as of December 31, 2003, were not on production.  These reserves have generally been non-producing for periods ranging from a few months to more than five years. In general, these reserves are related to commercially producible volumes that are awaiting production until production from another formation or zone in the same well bore is completed, or are related to reserves volumes which require the completion of infrastructure before production can begin.

11

Reconciliation of Reserves

The following tables reconcile Enerplus’ oil and natural gas reserves (on both a company interest and net basis) from December 31, 2002 to December 31, 2003, using forecast prices and costs. A significant portion of the “Technical Revisions” described in the following tables are attributable to the new methodology for determining and classifying oil and gas reserves under NI 51-101.  Additional information and details regarding the extent of the NI 51-101-related revisions is contained on pages 34 to 37 of the Fund’s 2003 Annual Report.

Reconciliation of Company Interest Reserves

	Light and Medium Crude Oil						Heavy Oil						Natural Gas Liquids
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2002	78,735		9,764		88,499		26,512		6,961		33,473		16,036		2,318		18,354
Acquisitions	8,841		1,454		10,295		24		43		67		805		122		927
Dispositions	(5,226	)	(1,485	)	(6,711	)	(16	)	(292	)	(308	)	(259	)	(35	)	(294	)
Extensions	372		49		421		—		—		—		94		—		94
Technical Revisions	(9,446	)	10,292		846		354		520		874		(1,415	)	1,073		(342	)
Discoveries	—		—		—		—		—		—		—		—		—
Economic Factors	(517	)	(824	)	(1,341	)	408		233		641		13		264		277
Improved Recovery	—		1,092		1,092		—		—		—		—		—		—
Production	(6,986	)	—		(6,986	)	(1,992	)	—		(1,992	)	(1,703	)	—		(1,703	)
December 31, 2003	65,773		20,342		86,115		25,290		7,465		32,755		13,571		3,742		17,313

	Associated and Non-Associated Gas (Natural Gas)						Total
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Bcf)		(Bcf)		(Bcf)		(MBOE)		(MBOE)		(MBOE)
December 31, 2002	1,002		139		1,141		288,267		42,175		330,442
Acquisitions	88		13		101		24,337		3,769		28,106
Dispositions	(10	)	(1	)	(11	)	(7,168	)	(2,034	)	(9,202	)
Extensions	9		3		12		2,025		541		2,566
Technical Revisions	(142	)	133		(9	)	(34,230	)	34,275		45
Discoveries	—		—		—		—		—		—
Economic Factors	8		(3	)	5		1,273		(920	)	353
Improved Recovery	—		—		—		—		1,092		1,092
Production	(88	)	—		(88	)	(25,336	)	—		(25,336	)
December 31, 2003	867		284		1,151		249,168		78,898		328,066

12

Reconciliation of Net Reserves

	Light and Medium Crude Oil						Heavy Oil						Natural Gas Liquids
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2002	71,758		8,505		80,263		23,034		6,001		29,035		11,309		1,631		12,940
Acquisitions	7,870		1,297		9,167		20		35		55		572		95		667
Dispositions	(4,652	)	(1,342	)	(5,994	)	(13	)	(240	)	(253	)	(184	)	(28	)	(212	)
Extensions	320		60		380		—		—		—		67		1		68
Technical Revisions	(9,590	)	8,916		(674	)	134		495		629		(1,085	)	735		(350	)
Discoveries	—		—		—		—		—		—		—		—		—
Economic Factors	(437	)	(712	)	(1,149	)	343		183		526		9		190		199
Improved Recovery	—		972		972		—		—		—		—		—		—
Production	(5,521	)	—		(5,521	)	(1,661	)	—		(1,661	)	(1,224	)	—		(1,224	)
December 31, 2003	59,748		17,696		77,444		21,857		6,474		28,331		9,464		2,624		12,088

	Associated and Non-Associated Gas (Natural Gas)						Total
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Bcf)		(Bcf)		(Bcf)		(MBOE)		(MBOE)		(MBOE)
December 31, 2002	806		114		920		240,353		35,143		275,496
Acquisitions	70		10		80		20,129		3,229		23,358
Dispositions	(8	)	(1	)	(9	)	(6,182	)	(1,777	)	(7,959	)
Extensions	7		3		10		1,554		561		2,115
Technical Revisions	(127	)	106		(21	)	(31,694	)	27,572		(4,122	)
Discoveries	—		—		—		—		—		—
Economic Factors	6		(2	)	4		915		(655	)	260
Improved Recovery	—		—		—		—		972		972
Production	(70	)	—		(70	)	(19,990	)	—		(19,990	)
December 31, 2003	684		230		914		205,085		65,045		270,130

13

Reconciliation of Changes in Net Present Value of Future Net Revenue

The following table sets forth a reconciliation of changes in the net present value of future net revenues associated with Enerplus’ Proved Reserves from December 31, 2002 to December 31, 2003 using constant prices and costs and discounted at 10% per year.

Period and Factor	Year Ended December 31, 2003
	(in $ millions)
Estimated Future Net Revenue at Beginning of Year	$	3,032.7
Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties	(453.8		)
Net Change in Prices, Production Costs and Royalties Related to Future Production	(409.8		)
Changes in Previously Estimated Development Costs Incurred During the Period	(70.2		)
Changes in Estimated Future Development Costs	22.0
Extensions and Improved Recovery	16.6
Discoveries	—
Acquisitions of Reserves	214.6
Dispositions of Reserves	(65.9		)
Net Change Resulting from Revisions in Quantity Estimates	(337.9		)
Accretion of Discount	273.4
Net Change in Income Taxes	N/A
Estimated Future Net Revenue at End of Year	$	2,221.7

Historical Undeveloped Reserves

The following table discloses the volumes of Undeveloped Reserves of Enerplus as at December 31, 2003 that were first attributed in 2003.

	Proved Undeveloped Reserves					Probable Undeveloped Reserves
	Crude Oil					Crude Oil
Year	Heavy	Light and Medium	NGLs	Natural Gas	Total	Heavy	Light and Medium	NGLs	Natural Gas	Total
	(Mbbls)	(Mbbls)	(Mbbls)	(Bcf)	(MBOE)	(Mbbls)	(Mbbls)	(Mbbls)	(Bcf)	(MBOE)
2003	950	320	35	27.5	5,888	74	263	80	33.9	6,067

Enerplus attributes Proved and Probable Undeveloped Reserves based on accepted engineering and geological practices as defined under NI 51-101. These practices include the determination of reserves based on the presence of commercial test rates from either production tests or drill stem tests, extensions of known accumulations based upon either geological or geophysical information and the optimization of existing fields. Enerplus has been very active for the last several years in drilling and developing these Undeveloped Reserves volumes, and based on Enerplus’ estimates of future capital expenditures, Enerplus expects to continue this activity.

14

OPERATIONAL INFORMATION

Description of Principal Properties

Outlined below is a description of Enerplus’ oil and natural gas operations and each of the Enerplus business units and their principal producing properties including, where applicable, the additional properties or working interests acquired through acquisitions during 2003. All production information represents Enerplus’ “company interest” in these properties before deduction of royalty interests owned by others. All references to reserve volumes are based upon the estimated volumes contained in the Sproule Report (using forecast prices and costs) applicable to Enerplus’  company interest reserves, before deduction of any royalties.See “Presentation of Enerplus’ Oil and Gas Reserves and Production Information”.

All of Enerplus’ oil and natural gas property interests are located in western Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba. All of Enerplus’ major properties have related field production facilities and infrastructure to accommodate Enerplus’ production. Production volumes for the year ended December 31, 2003 from Enerplus’ properties consisted of approximately 42% crude oil and NGLs and 58% natural gas on a BOE basis.  Enerplus’ 2003 production was comprised of average daily production of 24,597 bbls/d of crude oil, 4,666 bbls/d of NGLs and 240.9 MMcf/d of natural gas for a total of 69,414 BOE/d, an increase of 11% when compared to the previous year. During 2002, production consisted of 23,288 bbls/d of crude oil, 4,410 bbls/d of NGLs and 210.5 MMcf/d of natural gas for a total of 62,784 BOE/d. As at December 31, 2003, the oil and natural gas property interests held by Enerplus were estimated to contain Proved plus Probable Reserves of 136.2 MMbbls of crude oil and NGLs and 1,151 Bcf of natural gas for a total of 328.1 MMBOE.  See “Oil and Natural Gas Reserves”.

During 2002, Enerplus reorganized from a functionally aligned organization into a business unit structure, with four geographically distinct high working interest Enerplus-operated business units which accounted for approximately 60% of 2003 average daily production, and a joint venture business unit which accounted for approximately 40% of 2003 daily production. This restructuring enabled Enerplus to better focus its activities and is expected to improve operational and technical performance, operating results and capital efficiency.  Each of these five business units is a profit centre with a distinct team of engineers, geologists, operations personnel and landmen. Skill sets within each business unit are tailored to compliment the unique demands and opportunities within each area.

Joint Venture Business Unit

The Joint Venture Business Unit accounts for approximately 40% of Enerplus’ production and encompasses all partner-operated properties in western Canada from northeastern British Columbia to southeastern Saskatchewan.  These properties provide exposure to a wide variety of reservoirs, play types, and enhanced recovery projects that offer diversification to Enerplus’ asset base.  This business unit also provides exposure to higher impact, more technically complex projects than Enerplus might pursue on its own.

Production from this business unit for the year ended December 31, 2003 averaged 6,110 bbls/d of crude oil, 2,813 bbls/d of NGLs and 113.0 MMcf/d of natural gas for a total of 27,764 BOE/d. As at January 1, 2004, the Joint Venture Business Unit’s property interests contained 119.4 MMBOE of Proved plus Probable Reserves consisting of 36.9 MMbbls of crude oil and NGLs and 495.1 Bcf of natural gas.

The key properties within this business unit include the sweet, liquids rich natural gas plays in the Deep Basin region which encompasses the Elmworth, Karr, Wapiti, and South Wapiti producing fields, primarily operated by Burlington Resources Canada Ltd., Devon Canada Corporation and BP Canada Energy Company; interests in the sweet, liquids rich gas play in the Central Alberta Pine Creek area operated by Burlington Resources Canada Ltd. and Suncor Energy Inc. and interests in the Mount Benjamin property operated by Petro-Canada. The Mount Benjamin property is a deep foothills natural gas property where, during 2003, efforts were put into optimizing surface production facilities to maximize production from the area. Since acquiring this property in 2000, a total of five wells have been drilled with a 100% success rate, increasing production in a prolific natural gas area where significant production declines are more typical.

15

The Joint Venture Business Unit is also participating in a unique nitrogen injection pilot in the Turner Valley area outside of Calgary. This project, operated by Talisman Energy Inc., began operation in September of 2002 and to date, initial positive pressure responses had been observed. Although in a very early stage, if successful, it will lead to a full scale development program designed to recover an additional 3% to 10% of the estimated one billion barrels of crude oil reserves in place (approximately 1.5 to 5.0 million barrels of crude oil net to Enerplus).

During 2003, the acquisition of PCC added approximately 3,000 BOE/d of production to the Joint Venture Business Unit. Most of this production is generated from the greater Hanlan area which is comprised of deep, sour but high impact natural gas plays. This acquisition also brought significant development opportunities to Enerplus. Development capital relating to the PCC properties amounted to $10 million in 2003.

Major production facilities within this business unit include:  a 6% interest in the Elmworth Gas Plant; a 3% interest in Wapiti Gas Plants; a 10% interest in the Progress Gas Plant; an 8.5% in the Hanlan-Robb Sour Gas Plant; an 8% interest in a sweetening and absorption facility at Minnehik Buck Lake; a 2% interest in the Ram River sweetening and refrigeration facility; and a 22% interest in an emulsion treating and water disposal facility at Hayter.

Enerplus expects 2004 capital expenditures for this partner-operated business unit to remain consistent with 2003, with approximately 85% of Enerplus’ joint venture business unit capital budget focused on natural gas-weighted projects and 15% on oil-weighted projects. Additionally, as a continuation of its strategic investments in the Athabasca Oil Sands fairway, Enerplus will continue to fund the initial phases of the Joslyn Creek SAGD development project and expects to spend up to $6.0 million on this project in 2004, with initial production expected in mid-2004.

Southern Business Unit

The Southern Business Unit is Enerplus’ largest and most active operated development area encompassing long-life properties in southern Alberta and Saskatchewan.  It contains Enerplus’ core shallow natural gas development areas as well as a broad range of crude oil interests.  The majority of Enerplus’ operated natural gas production and development drilling is conducted in this business unit with over 200 operated shallow natural gas wells drilled in 2003. In addition, Enerplus successfully tested natural gas from coal in its Hanna and Bantry fields.  The Freda Lake Ratcliffe Unit, in which Enerplus acquired additional working interests in 2003, is also in this business unit, and along with the Medicine Hat Glauconitic “C” Pool contributes significant crude oil production.

Production from this business unit for the year ended December 31, 2003 averaged 3,838 bbls/d of crude oil, 36 bbls/d of NGLs and 59.9 MMcf/d of natural gas for a total of 13,849 BOE/d. As at January 1, 2004, the Southern Business Unit’s property interests contained 91.4 MMBOE of Proved plus Probable Reserves consisting of 22.7 MMbbls of crude oil and NGLs and 412.2 Bcf of natural gas.

The Southern Business Unit’s key natural gas producing properties include Hanna Garden Plains, Bantry, Verger, Countess and Medicine Hat Sun Valley, all of which have a large contiguous land base, pipeline infrastructure and major compression and dehydration facilities. The major crude producing property for this business unit is the previously mentioned Medicine Hat Glauconitic “C” Pool, which is under a waterflood recovery program. Various other minor properties contribute to the remainder of this business unit’s production, including the Heward, Saskatchewan area, where some significant emulsion treating and water disposal facilities are located.

Enerplus plans to continue shallow natural gas development drilling in 2004, including higher density drilling within existing producing areas. Confirmation of the viability of the increased density of well spacing will add further development opportunities in the future. Delineation of the natural gas bearing coal beds will continue in 2004 and could offer significant additional upside to take advantage of the land base and infrastructure. Enerplus also plans to continue crude oil development of the Medicine Hat Glauconitic “C” Pool and Freda Lake Ratcliffe pools.

16

Eastern Business Unit

The Eastern Business Unit focuses on waterflood development projects and encompasses operated properties and lands in eastern Alberta and western Saskatchewan along the provincial border.  This business unit is predominantly oil weighted with properties producing light sweet, medium quality and conventional heavy oil. The majority of these oil properties are under secondary recovery projects designed to improve production and enhance recoverable oil reserves. Optimization of these secondary recovery projects is key to maximizing the value of the assets in this business unit.

Production from this business unit for the year ended December 31, 2003 averaged 9,258 bbls/d of crude oil, 189 bbls/d of NGLs and 11.4 MMcf/d of natural gas for a total of 11,347 BOE/d. As at January 1, 2004, the Eastern Business Unit’s property interests contained 52.4 MMBOE of Proved plus Probable Reserves consisting of 41.1 MMbbls of crude oil and NGLs and 63.1 Bcf of natural gas.

The key properties within this business unit include Joarcam, Giltedge and Gleneath. Significant crude oil production installations for emulsion treating and water disposal or injection are found at Joarcam, Giltedge, Gleneath, Silver Heights, Shorncliff, newly acquired Shorncliff East, Cadogan, Kessler, David, Neutral Hills and Chauvin. In addition, Joarcam also has major facilities for natural gas compression, dehydration and processing.

Joarcam is Enerplus’ largest single producing field, producing both light sweet crude oil and natural gas, and has experienced a significant decrease in the production decline rate since Enerplus acquired and assumed operatorship of the property in late 2000. Through a series of optimization and development efforts, Enerplus has improved the decline rate from approximately 30% per year to approximately 10% per year.

The key waterflood recovery projects in this business unit were further reviewed in 2003 to ensure that they were fully optimized. These reviews provided opportunities to infill drill, recomplete and restimulate wells to improve production capability and enhance oil recovery. Development activities for 2004 will build on Enerplus’ historical success and continue to focus on improving and expanding its existing waterfloods to increase production and recovery. Divestments of minor interests and acquisitions in Enerplus’ core properties will increase the operational focus in the area.

Central Business Unit

The Central Business Unit is a mature producing area which covers the west-central portion of Alberta and provides a variety of production predominantly weighted to light quality sweet crude oil and liquids rich natural gas. Crude oil production in this business unit comes from reservoirs with long-life, shallow decline production profiles while gas is produced from high deliverability, large reserve natural gas pools.

Production from this business unit for the year ended December 31, 2003 averaged 2,924 bbls/d of crude oil, 1,192 bbls/d of NGLs and 34.2 MMcf/d of natural gas for a total of 9,822 BOE/d. As at January 1, 2004, the Central Business Unit’s property interests contained 47.7 MMBOE of Proved plus Probable Reserves consisting of 28.0 MMbbls of crude oil and NGLs and 118.4 Bcf of natural gas.

The Central Business Unit’s key producing property for 2003 was Pembina 5 Way, primarily a crude oil producing area with significant facilities for emulsion treating and water injection. Other significant properties within this business unit include Ferrier, Sylvan Lake, Kaybob South, and Pine Creek.

Development activity during 2003 was targeted at shallow natural gas drilling in the Sylvan Lake and Medicine River core areas.  An initiative to further exploit the shallow natural gas potential in additional properties within the Central Business Unit commenced in the latter half of 2003.

The focus of this business unit’s investment activity in 2004 will be to further develop its shallow natural gas program, including re-completions in potential uphole natural gas-bearing formations overlying oil production in the

17

Pembina area.  Enerplus also intends to re-evaluate continued infill drilling and recompletion initiatives to maintain light crude oil production in this region.

Northern Business Unit

The Northern Business Unit is a less developed region that encompasses all Enerplus-operated lands and production in northwest Alberta and northeast British Columbia.  This business unit provides exposure to both light crude oil and liquids rich natural gas through a variety of Triassic to Cretaceous age reservoirs and tends to offer high impact potential per well, although there are fewer drilling locations than in other business units. The Northern Business Unit’s key properties are two adjacent areas, Valhalla and Progress, both of which produce crude oil and natural gas. Other less significant properties include Clarke Lake, La Glace and Desmarais.

Production from this business unit for the year ended December 31, 2003 averaged 2,468 bbls/d of crude oil, 436 bbls/d of NGLs and 22.4 MMcf/d of natural gas for a total of 6,634 BOE/d. As at January 1, 2004, the Northern Business Unit’s property interests contained 17.2 MMBOE of Proved plus Probable Reserves consisting of 6.8 MMbbls of crude oil and NGLs and 62.2 Bcf of natural gas.

During 2003, development activities were primarily directed to improving light crude oil production at Valhalla and Progress while optimizing natural gas production at Progress, Bonanza and Valhalla through facility upgrades and development drilling. Since 1996, and particularly in recent years, Enerplus has steadily increased production from the Valhalla property through development efforts. In 2003, five wells were drilled in the Progress field to extend the Halfway B pool and enhance recovery in the Boundary pool, and two wells were drilled in the Valhalla Halfway J pool to enhance crude oil recovery and optimize the production from this pool. Facilities in the Progress areas were also enhanced and natural gas production was re-routed to the Progress Anadarko Plant to utilize Enerplus’ working interest to handle the sour natural gas volumes. In late 2003, non-core properties in the north central Alberta area surrounding Slave Lake were divested to enable the business unit to concentrate on core areas.

Development activities for 2004 will target additional development in Progress Halfway to further enhance production and recoverable reserves. Enerplus intends to lever its existing positions of undeveloped acreage and extensive seismic inventory, along with a review of non-productive wellbores, to further enhance this business unit’s development opportunities for value creation in 2004 and into the future.

Summary of Production Locations

During the year ended December 31, 2003, on a BOE basis, 88% of Enerplus’ production was derived from Alberta, 8% from Saskatchewan and 4% from British Columbia. The following table describes the major properties in each of Enerplus’ five business units and the average daily production from those properties during the year ended December 31, 2003:

18

	Product
	Crude Oil
Business Unit and Property	Heavy	Light and Medium	NGLs	Natural Gas	Total
	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(BOE/d)
Joint Venture Business Unit
Mount Benjamin	—	—	17	12,984	2,181
Elmworth	—	—	352	6,471	1,431
Pine Creek	—	1	290	5,960	1,285
Ferrier	—	60	258	4,520	1,072
South Wapiti	—	—	201	4,096	883
Hanlan	—	—	4	5,268	882
Rigel	—	742	7	208	783
Hayter	744	—	1	26	748
Mountain Park	—	—	6	4,186	703
Progress	—	46	71	3,422	687
Verger	—	—	—	3,588	598
Other	636	3,882	1,606	62,314	16,510
Total	1,380	4,730	2,813	113,043	27,764
Southern Business Unit
Bantry	—	2	—	14,436	2,408
Hanna Garden	—	2	1	12,708	2,121
Medicine Hat	1,667	—	—	962	1,827
Verger	—	6	—	7,998	1,339
Medicine Hat Sun Valley	—	2	—	6,588	1,100
Other	9	2,149	35	17,162	5,053
Total	1,676	2,161	36	59,854	13,849
Eastern Business Unit
Joarcam	—	2,152	145	6,066	3,308
Giltedge	1,852	—	—	399	1,919
Gleneath	—	1,117	22	444	1,213
Other	1,231	2,906	22	4,489	4,907
Total	3,083	6,175	189	11,399	11,347
Central Business Unit
Pembina 5 Way	—	2,156	126	1,619	2,553
Sylvan Lake	—	405	239	4,010	1,313
Ferrier	—	18	187	4,314	924
Pine Creek	—	7	178	4,354	910
Other	—	338	462	19,937	4,122
Total	—	2,924	1,192	34,234	9,822
Northern Business Unit
Valhalla	—	312	98	8,205	1,777
Progress	—	615	29	2,183	1,007
Other	—	1,542	309	11,988	3,849
Total	—	2,468	436	22,377	6,634
TOTAL	6,139	18,458	4,666	240,907	69,414

19

Oil and Natural Gas Wells and Unproved Properties

The following table summarizes, as at December 31, 2003, Enerplus’ interests in producing wells and in non-producing wells which were not producing but which may be capable of production, along with Enerplus’ interests in Unproved properties.  Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the proportion of oil or natural gas production that constitutes the majority of production from that well.

	Producing Wells				Non-Producing Wells				Unproved Properties
	Oil		Natural Gas		Oil		Natural Gas		(thousand of acres)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	4,203	1,476.3	4,684	2,358.4	853	311.4	286	105.8	696.3	277.9
Saskatchewan	2,948	579.6	359	261.1	278	48.0	5	0.9	35.9	35.6
British Columbia	289	36.6	116	27.5	62	9.6	53	15.4	77.1	25.9
Manitoba	28	28.0	—	—	—	—	—	—	0.6	0.6
Total	7,468	2,120.5	5,159	2,647.0	1,193	369.0	344	122.1	809.9	340.0

Enerplus expects its rights to explore, develop and exploit on approximately 70,000net acres to ordinarily expire prior to December 31, 2004.  Enerplus has no material work commitments on such properties and, where Enerplus determines appropriate, it can continue expiring leases by either making the necessary applications to extend or performing the necessary work.

Development Activities

The primary operational focus of Enerplus is to pursue attractive risk/return growth opportunities through the development of existing properties, the monetization of Enerplus’ exploratory lands and the acquisition of new properties.  Higher risk exploration plays are generally farmed out, sold, or exchanged for other interests with more attractive risk/return characteristics.  Enerplus will continue its ongoing property rationalization program on a selective basis and any sale proceeds may be used to acquire interests in existing core areas or new prospects with attractive exploitation opportunities.

During 2003, Enerplus participated in the drilling of543 gross wells (294 net wells) with a 98% net well success rate.  The majority of Enerplus’ 2003 wells were drilled in southern Alberta and southwest Saskatchewan in the operated shallow natural gas regions of Medicine Hat, Verger, Countess, Hanna Garden, Bantry and Fox Valley. Enerplus also participated in the drilling of an increased number of non-operated wells in the Deep Basin areas and foothills natural gas regions. The following table summarizes the number and type of wells that Enerplus drilled or participated in the drillingoffor the year ended December 31, 2003.Enerplus did not participate in drilling any exploratory wells in any such period.

	Number of Wells
Category of Well	Gross	Net
Crude oil wells	92	30.1
Natural gas wells	441	259.1
Dry and abandoned wells	10	4.6
	543	293.8
Service wells	—	—
Total	543	293.8

Enerplus currently intends to focus its development activities in the Western Canadian Sedimentary Basin.Enerplus’ development activities are typically funded through debt which is subsequently repaid through the issuance of Trust Units and internally generated cash flow. See “Additional Operational Information – Acquisition and Development Activities” below.

20

Quarterly Production History

The following table sets forth Enerplus’ average daily production volumes, on a company interest basis,for each fiscal quarter in 2003 and for the entire year.

	Year Ended December 31, 2003
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total for Year
Crude oil
Light and medium oil (bbls/d)	18,446	19,431	17,483	18,480	18,458
Heavy oil (bbls/d)	6,054	6,075	6,427	5,997	6,139
Total crude oil (bbls/d)	24,500	25,506	23,910	24,477	24,597
Natural gas liquids (bbls/d)	4,574	4,526	4,795	4,768	4,666
Total liquids (bbls/d)	29,074	30,032	28,705	29,245	29,263
Natural gas (Mcf/d)	232,911	243,540	243,458	243,573	240,907
Total (BOE/d)	67,893	70,622	69,281	69,841	69,414

Quarterly Netback History

The following tables set forth Enerplus’ average netbacks received for each fiscal quarter in 2003 and for the entire year (excluding any hedging gains or losses). Netbacks are calculated on the basis of prices received before hedging on sales volumes, less related royalties and related production costs. For multiple product well types, production costs are entirely attributed to that well’s principal product type.

Light and Medium Crude Oil ($ per bbl)

	Year Ended December 31, 2003
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Sales price	$	46.40		$	36.77		$	37.72		$	33.94		$	38.66
Royalties	(6.80		)	(5.35		)	(6.21		)	(6.02		)	(6.08		)
Production costs(1)	(10.37		)	(9.30		)	(11.89		)	(13.04		)	(11.13		)
Netback	$	29.23		$	22.12		$	19.62		$	14.88		$	21.45

Heavy Oil ($ per bbl)

	Year Ended December 31, 2003
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Sales price	$	35.23		$	27.63		$	27.44		$	24.32		$	28.61
Royalties	(6.44		)	(5.09		)	(5.29		)	(4.65		)	(5.37		)
Production costs(1)	(6.52		)	(8.86		)	(7.89		)	(10.55		)	(8.44		)
Netback	$	22.27		$	13.68		$	14.26		$	9.12		$	14.80

Natural Gas Liquids ($ per bbl)

	Year Ended December 31, 2003
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Sales price	$	36.34		$	31.76		$	30.04		$	35.66		$	33.43
Royalties	(9.84		)	(7.23		)	(7.57		)	(7.61		)	(8.05		)
Production costs(1)	—			—			—			—			—
Netback	$	26.50		$	24.53		$	22.47		$	28.05		$	25.38

21

Natural Gas ($ per Mcf)

	Year Ended December 31, 2003
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Sales price	$	8.10		$	6.32		$	5.78		$	5.10		$	6.30
Royalties	(1.85		)	(1.43		)	(1.25		)	(1.12		)	(1.41		)
Production costs(1)	(0.72		)	(0.88		)	(0.85		)	(1.03		)	(0.87		)
Netback	$	5.53		$	4.01		$	3.68		$	2.95		$	4.02

Total ($ per BOE)

	Year Ended December 31, 2003
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Sales price	$	46.01		$	36.33		$	34.47		$	31.36		$	36.94
Royalties	(9.45		)	(7.32		)	(6.98		)	(6.42		)	(7.51		)
Production costs(1)	(5.86		)	(6.34		)	(6.70		)	(7.98		)	(6.73		)
Netback	$	30.70		$	22.67		$	20.79		$	16.96		$	22.70

Note:

(1) Production costs are costs incurred to operate and maintain wells and related equipment and facilities, including operating costs of support equipment used in oil and gas activities and other costs of operating and maintaining those wells and related equipment and facilities.  Examples of productions costs include items such as field staff labour costs, costs of materials, supplies and fuel consumed and supplies utilized in operating the wells and related equipment (such as power, chemicals and lease rentals), repairs and maintenance costs, property taxes, insurance costs, costs of workovers, processing and treating fees, overhead fees, taxes (other than income and capital taxes) and other costs.

Abandonment and Reclamation Costs

In connection with its operations, Enerplus will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. Enerplus estimates such costs through a model that incorporates data from Enerplus’ operating history, a cost formula used by the Alberta Energy Utilities Board and industry information sources, together with other operating assumptions. Enerplus expects all of its net wells to incur these costs. Enerplus anticipates the total amount of such costs, net of estimated salvage value for such equipment, to be approximately $234 million on an undiscounted basis and $35 million discounted at 10%. Additionally, of this amount, the calculations of future net revenue in the tables under “Oil and Natural Gas Reserves” above have excluded approximately $93 million on an undiscounted basis and $14 million discounted at 10% as these calculations do not reflect any costs for abandonment and reclamation for facilities and wells for which no reserves have been attributed.  In the next three financial years, Enerplus anticipates that a total of approximately $21 million on an undiscounted basis and $17.3 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

Tax Horizon

None of the Fund or its operating subsidiaries were required to pay income taxes for the year ended December 31, 2003.  See Note 5 to the Fund’s audited financial statements for the year ended December 31, 2003. Under Enerplus’ current structure and existing tax legislation, annual taxable income is transferred from its operating entities to the Fund through interest and royalty payments. The Fund, in turn, allocates all of its taxable income to unitholders through payment of cash distributions and therefore no cash income tax is incurred in the Fund or its operating subsidiaries.

Costs Incurred

In the financial year ended December 31, 2003, Enerplus expended a total of $225.3 million on corporate and property acquisitions, as well as $157.7 million for development and facilities costs.

22

Marketing Arrangements and Forward Contracts

Crude Oil and NGLs

Enerplus’ crude oil and NGLs production is marketed to a diverse portfolio of intermediaries and end users on 30 day continuously renewing contracts whose terms fluctuate with monthly spot market prices.  Enerplus received an average price before hedging of $36.15/bbl for its crude oil and $33.43/bbl for its NGLs for the year ended December 31, 2003, compared to $34.37/bbl for crude oil and $25.68/bbl for NGLs for the year ended December 31, 2002.

Natural Gas

In marketing its natural gas production, Enerplus’ efforts are directed to achieve a mix of contracts, customers, and geographic markets. Enerplus sells approximately one-third of its natural gas production under aggregator contracts wherein a large pool of reserve based natural gas production is aggregated and sold downstream under long term transportation and sales contracts to a variety of end users. The entire sales proceeds and transportation costs are pooled and paid equitable to all supply producers. In 2003, these aggregators contracts returned a price just slightly lower than the monthly Alberta spot market price. As well, Enerplus has its own firm transportation commitments to deliver natural gas into the U.S. midwest (Chicago) area. These contracts comprise 10 MMcf/d on Foothills and Northern Border pipelines until October 31, 2008; 5 MMcf/d on the Alliance Pipeline until October 31, 2015; and 5 MMcf/d to Marshfield, Illinois on the TransCanada and Viking Pipelines until October 2008. The remainder of Enerplus’ natural gas production is sold primarily in the provinces of Alberta, Saskatchewan and British Columbia at prevailing spot market prices.

Enerplus’ percentage of 2003 revenues attributable to natural gas, before hedging, was 59% compared to 47% in 2002, notwithstanding that natural gas represented over 55% of Enerplus’ total production in both 2003 and 2002. The average price received by Enerplus, before hedging, for its natural gas in 2003 was $6.30/Mcf compared to $3.87/Mcf in the year ended December 31, 2002.

Future Commitments and Forward Contracts

Enerplus uses various types of financial instruments and fixed price physical sales contracts to manage the risk related to fluctuating commodity prices.  Absent such hedging activities, all of the crude oil and NGLs and the majority of natural gas production of Enerplus is sold into the open market at prevailing spot prices, which exposes Enerplus to the risks associated with commodity price fluctuations and foreign exchange rates.  See “Risk Factors”.  Information regarding Enerplus’ financial and physical instruments is contained in Note 8 to the Fund’s audited annual consolidated financial statements for the year ended December 31, 2003 and under the heading “Pricing and Price Risk Management” in the Fund’s management’s discussion and analysis for the year ended December 31, 2003 which is contained on pages56 to 58 of the Fund’s 2003 Annual Report, both of which are incorporated herein by reference.

Environment, Health and Safety

Enerplus places a high priority on protecting the environment and on the health and safety of its employees, contractors and the public.  Enerplus recognizes the value of maintaining superior environment, health and safety (“EHS”) standards and actively manages programs to support and measure efforts for further improvement.

Enerplus monitors the key industry benchmarks of recordable and lost time injuries for employees and contractors.  Enerplus’ results compare favourably to industry data as its employees have not experienced a loss time accident since 2000 and have consistently outperformed the employee recordable injury index as measured against benchmark data provided by the Canadian Association of Petroleum Producers (“CAPP”).  The Enerplus EHS Management System includes ongoing assessments designed to support top tier performance and continuous improvement as demonstrated by the following initiatives:

23

•Enerplus achieved a 94% rating from a third party audit conducted on its Certificate of Recognition in the Partnership Program with Alberta Human Resources and Employment and the Workers Compensation Board;

•Enerplus continues to participate at a Platinum Level, the highest level attainable, in the Environmental Health and Safety Stewardship Program initiated by CAPP;

•an internal EHS Steering Committee was formed, comprised of executives, managers and EHS staff, to address environmental, health and safety standards and policies.  The committee’s functions include enhancements to programs to ensure hazardous tasks are carried out safely, responsibly and effectively; and

•as part of a Corrosion Integrity Management Program, Enerplus continues to provide inspection and upgrading of its production infrastructure to minimize potential environmental and financial impacts.  During 2003 approximately 2,000 kilometers (representing approximately 43%) of Enerplus’ pipelines were flow modeled and risk assessed, 410 (25%) of its tanks were inspected or leak tested, and 100% of the required pressure vessels inspections were completed. Enerplus also successfully achieved the Alberta Boiler Safety Association external three-year audit renewal.

Environmental, health and safety risks influence Enerplus’ workforce as well as its operating and capital costs. In addition, the oil and gas industry is subject to numerous related laws and regulations.  See “Industry Conditions – Environmental Regulation”.  Enerplus mitigates these risks through the following measures:

•developing and adhering to standards, procedures and practices that protect the environment, and the health and safety of Enerplus employees, contractors and the public, that meet or exceed the government regulations and requirements;

•health and safety inspections and audits are conducted regularly to ensure hazards are identified and controlled. Enerplus conducts both internal and third party site inspections at selected facilities, construction and drilling projects each year;

•all reported incidents are reviewed to understand the underlying causes in order to prevent reoccurrence and raise safety awareness of employees and contractors;

•environmental inspections are conducted regularly to identify environmental liabilities and correct Enerplus’ well site and facility reclamation and abandonment program;

•ensuring that emergency response plans meet all regulatory requirements and are in place and practiced regularly to prevent and deal with incidents quickly and effectively; and

•conducting thorough due diligence investigations on potential acquisitions to ensure that environmental liabilities and safety concerns are identified and properly quantified.

Impact of Environmental Protection Requirements

Enerplus carries out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice.  See “Information Respecting Enerplus Resources Fund - Operations of Enerplus - Environmental Obligations”.  At present, Enerplus believes that it meets all applicable environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet its ongoing environmental obligations. The costs incurred by Enerplus in respect of continued environmental compliance and site restoration costs amounted to approximately 4% of the total development expenditures incurred by Enerplus in 2003.  Since the environmental standards and regulations to which Enerplus is subject (including the Kyoto Protocol) generally apply to all participants in the oil and gas industry, it is not anticipated that Enerplus’ competitive position within the industry, particularly among issuers holding properties with similar characteristics, will be adversely affected.  See “Industry Conditions - Environmental Regulation” and “Risk Factors”.

24

Additional Operational Information

Management Policies

The board of directors of EnerMark oversees the business and affairs of Enerplus. It supervises Enerplus’ management as it manages and administers the business and operations of Enerplus in accordance with general policies and principles established by the EnerMark directors.  The strategies employed and activities undertaken by the EnerMark directors and Enerplus management are directed towards maximizing distributable income to the unitholders while at the same time striving for long-term growth in the value of the assets of Enerplus. These two objectives are fundamental to the operation of Enerplus and are balanced to maximize benefit to the unitholders. Enerplus utilizes its extensive experience and employs prudent oil and gas business practices to increase the value of the assets of Enerplus through the acquisition and development of producing oil and gas properties.

Acquisition and Development Activities

The primary operational focus of Enerplus is to pursue growth opportunities through the acquisition and development of mature, lower-risk, long-life oil and natural gas properties.  Since Enerplus does not generally engage in exploration activities, it relies primarily upon acquisitions to both replenish and add to its oil and natural gas reserves.  Enerplus acquires properties and assets which are consistent with the guidelines for acquisitions which may be established from time to time by the board of directors of EnerMark. Any conventional oil and gas asset or property acquisition (or disposition) with a value of greater than $25 million requires the approval of the directors of EnerMark.  In pursuing acquisitions, Enerplus employs a focused and disciplined strategy to ensure that the reserves being considered are a strategic fit with its existing portfolio of properties.  Enerplus has typically funded its acquisitions through either borrowings from its existing credit facility or the direct issuance of Trust Units.  Borrowings are subsequently repaid through the issuance of additional Trust Units or from internally-generated cash flows.  This strategy provides Enerplus with the flexibility to respond to acquisition opportunities on a timely basis.

To the extent its acquisitions include higher risk exploration opportunities, Enerplus enters into farmout or swap agreements under which an exploration and production company will explore and drill these opportunities on Enerplus’ behalf, generally at no cost to Enerplus, in exchange for a portion of Enerplus’ interests in the property.  Other exploration properties may be sold to allow Enerplus to focus on more attractive risk/return development activities, as discussed elsewhere in this Annual Information Form.

Enerplus undertakes attractive risk/return development activities to mitigate declines in total production, upgrade its reserves and extend the useful lives of many of its properties.  Development activities are particularly important to Enerplus during periods when there are a limited number of attractive acquisition opportunities.  Enerplus’ development activities provide a lower-risk, less capital intensive alternative for increasing production volumes than do traditional exploration activities.  Enerplus’ development activities are typically funded through debt which is subsequently repaid through the issuance of Trust Units and internally generated cash flow.

Insurance

Enerplus carries insurance coverage to protect its assets at or above the standards typical within the oil and natural gas industry.  Coverages are determined and placed by Enerplus after considering the perceived risk of loss, limit of coverage determined appropriate and the cost of coverages.  Coverages currently in place include protection against third party liability, property damage or loss, and, for certain properties, business interruption.  In addition, director and officer liability coverage is also carried for directors and officers of Enerplus.

Borrowing

The Fund may, provided that the approval of the board of directors of EnerMark has been obtained, borrow, incur indebtedness, give any guarantee or enter into any subordination agreement on behalf of the Fund, or pledge or provide any security interest or encumbrance on any property of the Fund.  At present, all indebtedness of Enerplus is incurred directly by its primary operating subsidiary, EnerMark.  Details of EnerMark’s debt arrangements are

25

contained in Note 3 to the Fund’s audited annual consolidated financial statements for the year ended December 31, 2003 and under the heading “Liquidity and Capital Resources” in Enerplus’ management discussion and analysis, contained on page 66 of the Fund’s 2003 Annual Report, each of which is incorporated herein by reference.  The indebtedness of Enerplus to its lenders and senior noteholders ranks senior and is in priority to the royalty, interest and dividend payments that are made to the Fund by its operating subsidiaries, and therefore ahead of distributions from the Fund to its unitholders.  See “Information Respecting Enerplus Resources Fund – Description of the Royalty Agreements and Subordinated Notes” and “Risk Factors”.

Records

Enerplus keeps those books and records as are necessary for the proper recording of the business transactions of the Fund.  These records are, as nearly as practicable, in accordance with those required to be maintained by a distributing corporation incorporated under the Business Corporations Act (Alberta). Unitholders at all times have access to these records to the same extent as though they were shareholders of such a corporation.  All such records are kept by Enerplus at its office in Calgary, Alberta.

Personnel

As at December 31, 2003, Enerplus employed a total of 456 persons.

26

INFORMATION RESPECTING ENERPLUS RESOURCES FUND

Description of the Trust Units and the Trust Indenture

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

General

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

Trust Units and Other Securities of the Fund

The Fund is authorized to issue an unlimited number of Trust Units and each Trust Unit represents an equal undivided beneficial interest in the Fund. All Trust Units share equally in all distributions from the Fund and in the net assets of the Fund upon the termination or winding-up of the Fund.  Each Trust Unit entitles the holder thereof to one vote at meetings of unitholders.  No unitholder will be liable to pay any further calls or assessments in respect of the Trust Units. No conversion or pre-emptive rights attach to the Trust Units.

The Trust Indenture provides that the directors of EnerMark may from time to time authorize the creation and issuance of options, rights, warrants or similar rights to acquire Trust Units or other securities convertible or exchangeable into Trust Units, on the terms and conditions as the directors of EnerMark may determine. A right, warrant, option or other similar security is not considered to be a Trust Unit and a holder of such securities is not considered to be a unitholder of Enerplus. Additionally, the directors of EnerMark may authorize the creation and issuance of debentures, notes and other indebtedness of the Fund on such terms and conditions as the directors of EnerMark may determine.

The Trustee

CIBC Mellon Trust Company is the trustee of the Fund and also acts as transfer agent and registrar for the Trust Units. The Trust Indenture provides that, subject to the specific limitations and the grant of powers to EnerMark contained in the Trust Indenture, the Trustee has full, absolute and exclusive power, control and authority over the property of the Fund and over the affairs of the Fund to the same extent as if the Trustee were the sole owner of such property in its own right, and may do all such acts and things as it, in its sole judgment and discretion, deems necessary or incidental to, or desirable for, the carrying out of the duties of the Trustee as established pursuant to the Trust Indenture.  In particular, among other things, the Trustee is responsible for making the payment of distributions or other property to unitholders, maintaining certain records of the Fund and providing certain reports to unitholders.

However, certain powers, authorities and obligations have been granted to EnerMark in the Trust Indenture, including the responsibility for the general administration and management of the day to day affairs and operations of the Fund. Other powers and responsibilities may be delegated to such other persons as the Fund Trustee may deem necessary or desirable. See “Responsibilities of and Delegation to EnerMark” below.

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

27

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

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

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

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

Responsibilities of and Delegation to EnerMark

Under the Trust Indenture, in addition to the duties of EnerMark described elsewhere in this Annual Information Form, EnerMark has been allocated the responsibility for the general administration and management of the affairs and day-to-day operations of the Fund.  The Trustee is also authorized to delegate any of the powers and duties granted to it (to the extent not prohibited by law) to any person as the Trustee may deem necessary or desirable.  All significant operational and strategic matters relating to the Fund have been either granted or delegated to EnerMark in the Trust Indenture including, among other things, the responsibility to: (i) determine the timing and terms of future offerings or repurchases of Trust Units and other securities of the Fund; (ii) undertake all matters relating to borrowings by the Fund, including the granting of security and subordination agreements by the Fund; (iii) vote all securities held by the Fund (subject to restrictions in the Trust Indenture); (iv) approve the Fund’s public disclosure documents; (v) undertake all matters pertaining to any take-over bid, merger, amalgamation, arrangement, substantial asset acquisition or similar transaction involving the Fund; (vi) ensure compliance by the Fund with its continuous disclosure obligations under applicable securities laws; (vii) provide investor relations services; (viii) prepare and cause to be provided to unitholders all information to which unitholders are entitled under the Trust Indenture and under applicable laws; (ix) call and hold meetings of unitholders and prepare, approve and arrange for the distribution of required materials, including notices of meetings and information circulars, in respect of all such meetings; (x) compute, determine, approve and direct the Trustee to make distributions to unitholders; and (xi) use its best efforts to ensure the Fund maintains its status as a mutual fund trust under the Tax Act.  The Trust Indenture permits EnerMark to delegate its responsibilities, but no such delegation will relieve EnerMark of its obligations under the Trust Indenture.  If, however, EnerMark delegates its responsibilities to a third party and in so doing does not breach its standard of care, EnerMark will not be liable for the acts or omissions of such delegate.

28

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

Certain Restrictions on Powers of the Trustee and EnerMark

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

(i)amend the Trust Indenture (except in certain circumstances described under “Amendments to the Trust Indenture” below);

(ii)sell, assign, lease, exchange or otherwise dispose of, or agree to do so, all or substantially all of the property and assets of the Fund, other than (A) in conjunction with an internal reorganization of the direct or indirect assets of the Fund as a result of which the Fund has the same direct or indirect interest in such property and assets that it had prior to the reorganization, or (B) pursuant to a pledge relating to indebtedness of the Fund or its subsidiaries;

(iii)authorize the termination, liquidation or winding-up of the Fund; or

(iv)authorize the combination, merger or similar transaction between the Fund and any other person that is not an affiliate or associate of the Fund, except in connection with an internal reorganization of the Fund and its affiliates (but for greater certainty, a take-over bid by or on behalf of the Fund, an acquisition by or on behalf of the Fund by way of plan of arrangement or the acquisition by the Fund of all or substantially all of the assets of another person shall not be subject to the approval of the unitholders).

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

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

Non-Resident Ownership Provisions

In order for the Fund to maintain its status as a mutual fund trust under the Tax Act, it may be necessary for the Fund to ensure that it has not been established or maintained primarily for the benefit of non-residents of Canada (“non-residents”) within the meaning of the Tax Act.  Accordingly, the Trust Indenture provides that, from time to time, EnerMark may restrict the number of Trust Units owned by non-residents and take all necessary steps to monitor the ownership of the Trust Units such that the Fund maintains the status of a unit trust and mutual fund trust for the purposes of the Tax Act.  The Trust Indenture also provides that, if at any time EnerMark becomes aware that the

29

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

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

For additional information regarding non-resident ownership restrictions and developments, see “General Development of Enerplus Resources Fund – Recent Developments – Non-Resident Ownership, Mutual Fund Trust Status and Impact of 2004 Canadian Federal Governmental Budget Proposals” and “Risk Factors”.

Investments of the Fund

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

Distributions of Distributable Income

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

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

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

30

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

Meetings of Unitholders and Voting

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

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

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

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

Redemption Right

Each unitholder is entitled to require the Fund to redeem at any time or from time to time, at the demand of the unitholder and upon receipt by the Fund of a duly completed and properly executed notice requesting such redemption, all or any part of the Trust Units registered in the name of the unitholder at a price per Trust Unit equal to the lesser of:

(a)85% of the market price (as defined in the Trust Indenture) of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 day trading period commencing immediately after the date on which the Trust Units were tendered to the Fund for redemption; and

31

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

The price that unitholders receive for Trust Units surrendered for redemption during any calendar month will be paid to the unitholder on the last day of the following month. There is however a limitation on the amount of cash that the Fund can pay for redemptions. The maximum amount of cash that the Fund can pay for all Trust Units surrendered for redemption in any calendar month and the preceding calendar month cannot exceed $500,000, although EnerMark has the ability to waive this limitation at its discretion. If a unitholder is not entitled to receive a cash payment for Trust Units surrendered for redemption as a result of such limitations, a unitholder will receive notes or other investments of the Fund, subject to receipt of any applicable regulatory approvals. If at the time that a unitholder surrenders his or her Trust Units for redemption, the Trust Units are not listed for trading on the Toronto Stock Exchange or another market which EnerMark considers, in its sole discretion, provides representative fair market value prices for the Trust Units, or if the normal trading of the Trust Units has been suspended or halted, the unitholder will receive a price per Trust Unit equal to 85% of the fair market value as determined by EnerMark as at the redemption date.

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

Repurchase of Trust Units

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

Term and Termination of the Fund

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

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

After the date on which the Trustee is required to commence to wind up the affairs of the Fund, the Trustee will generally carry on no activities except for the purpose of winding up the affairs of the Fund and, for this purpose, the Trustee will continue to be vested with and may exercise all or any of the powers conferred upon the Trustee under the Trust Indenture.

32

Reporting to Unitholders

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

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

Auditors

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

Amendments to the Trust Indenture

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

(a)ensuring that the Fund will comply with any applicable laws or requirements of any governmental agency or authority of Canada or of any province;

(b)ensuring that the Fund will maintain its status as a “unit trust” or “mutual fund trust”, and not become foreign property, pursuant to the Tax Act;

(c)ensuring that such additional protection is provided for the interests of unitholders as the Trustee or EnerMark may consider expedient;

(d)removing any conflicts or inconsistencies between the provisions of the Trust Indenture or any supplemental indenture and any prospectus filed with any regulatory or governmental body with respect to the Fund, or any applicable law or regulation of any jurisdiction, if, in the opinion of the Trustee, such an amendment will not be detrimental to the interests of the unitholders;

(e)adding to the provisions of the Trust Indenture such additional covenants and enforcement provisions as, in the opinion of counsel, are necessary or advisable, or making such provisions not inconsistent with the Trust Indenture as may be necessary or desirable with respect to matters or questions arising under the Trust Indenture, provided that the same are not, in the opinion of the Trustee, prejudicial to the interests of the unitholders;

(f)modifying any of the provisions of the Trust Indenture, including relieving EnerMark from any of its obligations, conditions or restrictions, provided that such modification or relief shall be or become operative or effective only if, in the opinion of the Trustee, such modification or relief is not prejudicial to the interests of the unitholders; and

33

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

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

Description of the Royalty Agreements and Subordinated Note

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

Royalty Agreements

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

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

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

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

Unsecured, Subordinated Promissory Note of EnerMark

EnerMark has issued an unsecured, subordinated promissory note to the Fund. The subordinated note bears interest at an annual rate of 8% and the principal amount of the note varies as additional funds (generally from the issuance of Trust Units) are loaned from the Fund to EnerMark and principal repayments are made on the note. The maturity date of the note is June 21, 2015. The payment of principal and interest on the note is subordinated to the prior payment in full of all other debt of EnerMark, other than debt which, by its terms or by operation of law, ranks equal

34

with the subordinated note.  The Fund has entered into a subordination agreement pursuant to which the payment to the Fund by EnerMark of obligations under the subordinated note is subordinated and will rank junior to the indebtedness of EnerMark to its lenders and the holders of its senior unsecured notes.

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

As stated above, the terms of the existing royalty agreements and the promissory note issued by EnerMark to the Fund, together with the subordination agreements entered into by the Fund and the terms of EnerMark’s credit facilities and senior notes, result in the royalty, interest and dividend payments from the Fund’s operating subsidiaries to the Fund being subordinate to payments made, or required to be made, on indebtedness to third parties. As a result, royalty, interest and dividend payments from EnerMark, ERC and EOG to the Fund, and the related cash distributions from the Fund to unitholders, may be adversely affect if EnerMark is in default of such indebtedness or if there are variations in the terms of EnerMark’s indebtedness to third parties, including interest rates or the timing or principal repayments.  See “Risk Factors”.

Management and Corporate Governance

Under the terms of the Trust Indenture, subject to certain powers remaining with the Trustee, EnerMark has been allocated the responsibility for the general administration and management of the affairs and day-to-day operations of the Fund.  See “Information Respecting Enerplus Resources Fund – Description of the Trust Units and the Trust Indenture – Responsibilities of and Delegation to EnerMark” and see “Directors and Officers”.

Information regarding the Fund’s corporate governance and the duties and procedures of the EnerMark board of directors and its committees is contained under the heading “Corporate Governance” on pages 44 to 49 of the Fund’s 2003 Annual Report and under the heading “Statement of Corporate Governance Practices” in the Fund’s information circular and proxy statement dated March 17, 2004.

Unitholder Rights Plan

On March 5, 1999, the Fund entered into a Unitholder Rights Plan Agreement (the “Rights Plan”) with CIBC Mellon Trust Company, as Rights Agent, which was approved by Enerplus’ unitholders on April 23, 1999 and was renewed for an additional three years by the Enerplus unitholders at the 2002 annual general and special meeting of unitholders.  The Rights Plan generally provides that following any person or entity acquiring 20% or more of the issued and outstanding Trust Units (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Trust Units, other than such person or entity, shall be entitled to acquire Trust Units at a discounted price.  The Rights Plan is similar to other shareholder or unitholder rights plans adopted in the energy sector.

DISTRIBUTIONS TO UNITHOLDERS

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

Distributable Income

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

35

The amount of cash flow paid to the Fund from its operating subsidiaries, and the amount of cash distributions subsequently paid by the Fund to unitholders, depends on numerous factors including the operating entities’ financial performance, debt covenants and obligations, working capital requirements and future capital requirements. Such amounts are, in part, subject to the discretion of the board of directors of EnerMark, which determines both the extent to which cash flow will be allocated to the repayment of debt, as well as the amount of cash flow to apply to capital expenditures.  The board of directors of EnerMark regularly evaluates the Fund’s distribution payout with respect to forecast cash flows, debt levels and capital expenditures plans.  In the past, the level of cash retained for debt repayment has typically varied between 10% and 25% of the total annual cash flow.  For the year ended December 31, 2003, approximately 19% of the cash available for distribution was retained for debt repayment (approximately 8% after costs associated with the management internalization of EGEM).

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

Distribution History

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

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

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

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

Note:

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

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

36

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. Regulatory approvals must be obtained before drilling wells or constructing facilities. Failure to obtain such approvals on a timely basis could result in delays or abandonment of projects and increased costs.  Although it is not expected that any of these controls or regulations will affect Enerplus’ operations in a manner materially different than they would affect other Canadian oil and gas issuers of similar size, the controls and regulations should be considered carefully by investors in the oil and gas industry. All current legislation is a matter of public record and Enerplus is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in western Canada.

Pricing and Marketing - Oil

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

Pricing and Marketing - Natural Gas

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

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

The North American Free Trade Agreement (“NAFTA”)

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

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

37

Provincial Royalties and Incentives

General

In addition to federal regulations, each province in Canada has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown-owned lands are determined by negotiations between the freehold mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties or net profits or net carried interests.

From time to time, the federal and provincial governments in Canada have established incentive programs which have included royalty rate reductions (including for specific wells), royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects, although the trend is toward eliminating these types of programs in favour of long term programs which enhance predictability for producers.  If applicable, oil and natural gas royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers.

Alberta

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

In Alberta, the amount payable to the Alberta government as a royalty in respect of oil depends on the type of oil, the vintage of the oil, the quantity of oil produced in a month and the value of the oil. The vintage of oil is determined based on various criteria set out in the regulations, but is generally broken down into three categories being old oil, new oil and third tier oil (which is oil produced form pools discovered after September 30, 1992).  The royalty rate on old oil is between 10% and 35%, for new oil it is between 10% and 30%, and for third tier oil it is between 10% and 25%.

The royalty payable to the Alberta government in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the type of natural gas, the quantity produced in a given month and the vintage of the natural gas. The vintage of natural gas is based on various criteria set out in the regulations, but is generally determined based on when the natural gas pools were discovered and natural gas from such pools was recovered.  As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than non-associated natural gas. The royalty payable on natural gas varies between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 is eligible for a royalty exemption for a period of 12 months, up to a prescribed maximum amount.  Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well.

38

British Columbia

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

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

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month and the value of the oil. The royalty rate payable for old oil is between 20% and 45%, and for new oil and third tier oil is between 10% and 35%. The royalty payable on natural gas in Saskatchewan is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than non-associated natural gas. The royalty rate payable for old gas is between 20% and 45%, and for new gas and third tier gas is between 15% and 35%.

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

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

39

drilling date on or after October 1, 2002 will receive fourth tier royalty/tax rates and incentive volumes. Further changes include the reduction of the corporation capital tax resource surcharge rate from 3.6% to 2.0% and, subject to certain restrictions, the expansion of the deep oil well definition to include oil wells producing from a zone deeper than 1,700 meters.

Land Tenure

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

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well, pipeline and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures.  A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage.

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

In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require participating countries, upon ratification, to reduce their emissions of carbon dioxide and other greenhouse gases.Canada ratified the Kyoto Protocol in late 2002.  Although the Canadian federal government has not released details of any implementation plan, it has stated that it intends to limit the emission reduction targets for the industry and the cost of emission credits, which could result in increased capital expenditures and operating costs.

Enerplus believes that it is, and intends to continue to be, in material compliance with applicable environmental laws and regulations and is committed to meeting its responsibilities to protect the environment wherever it operates or holds working interests.  Enerplus anticipates that this compliance may result in increased expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment.  Enerplus believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

40

RISK FACTORS

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

Risks Related to Enerplus’ Business and Operations

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

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

•global energy policy, including the ability of OPEC to set and maintain production levels and prices for oil;

•political conditions, including the risk of hostilities in the Middle East;

•global and domestic economic conditions;

•weather conditions;

•the supply and price of imported oil and liquefied natural gas;

•the production and storage levels of North American natural gas;

•the level of consumer demand;

•the price and availability of alternative fuels;

•the proximity of reserves to, and capacity of, transportation facilities;

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

•government regulations.

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

Enerplus uses financial derivative instruments and other hedging mechanisms to try to limit a portion of the adverse effects resulting from volatility in natural gas and oil commodity prices.  To the extent Enerplus hedges its commodity price exposure, it may forego the benefits it would otherwise experience if commodity prices were to increase.  In addition, Enerplus’ commodity hedging activities could expose it to losses.  These losses could occur under various circumstances, including if the other party to Enerplus’ hedge does not perform its obligations under the hedge agreement.

41

An increase in operating costs or a decline in Enerplus’ production level could have a material adverse effect on results of operations and financial condition and, therefore, could reduce distributions to unitholders.

Higher operating costs for the underlying properties of Enerplus will directly decrease the amount of cash flow received by the Fund and, therefore, may reduce distributions to Enerplus’ unitholders.  Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of Enerplus’ operating costs that are susceptible to material fluctuation.

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

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

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

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

Fluctuations in foreign currency exchange rates could adversely affect Enerplus’ business.

The price that Enerplus receives for a majority of its oil and natural gas is based on United States dollar denominated benchmarks, and therefore the price that Enerplus receives in Canadian dollars is affected by the exchange rate between the two currencies.  A material increase in the value of the Canadian dollar relative to the United States dollar may negatively impact Enerplus’ net production revenue by decreasing the Canadian dollars Enerplus receives for a given United States dollar price. Currently, Enerplus does not engage in significant risk management activities related to foreign exchange rates, with the exception of the cross-currency swap associated with the US$175 million of senior unsecured notes issued by EnerMark in June 2002, as described in Notes 3(b) and 8(b) to the Fund’s audited consolidated financial statements for the year ended December 31, 2003.

42

If Enerplus is unable to acquire additional reserves, the value of the Trust Units and the Fund’s distributions to unitholders may decline.

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

Acquisitions are subject to exploitation and development risks which may affect the value of the Trust Units and distributions to unitholders.

Exploitation and development risks arise for Enerplus and, as a result, may affect the value of the Trust Units and distributions to unitholders due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods.  Exploitation and development risks are mitigated by using highly skilled staff, focusing exploitation efforts in areas in which Enerplus has existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods and controlling costs to maximize returns.  Advanced oil and natural gas related technologies such as three dimensional seismography, reservoir simulation studies and horizontal drilling are also used by Enerplus to improve its ability to find, develop and produce oil and natural gas.

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

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

•historical production in the area compared with production rates from similar producing areas;

•future commodity prices, production and development costs, royalties and capital expenditures;

•initial production rates;

•production decline rates;

•ultimate recovery of reserves;

•success of future exploitation activities;

•marketability of production;

•effects of government regulation; and

•other government levies that may be imposed over the producing life of reserves.

Reserve estimates are based on the relevant factors, assumptions and prices on the date the evaluations were prepared. Many of these factors are subject to change and are beyond Enerplus’ control.  If these factors,

43

assumptions and prices prove to be inaccurate, Enerplus’ actual reserves could vary materially from its reserve estimates.

In determining the purchase price of acquisitions, Enerplus relies on estimates of reserves that may prove to be inaccurate.

The price that Enerplus is willing to pay for reserve acquisitions is based largely on its estimates of the reserves to be acquired.  Actual reserves could vary materially from these estimates. Consequently, the reserves that Enerplus acquires may be less than it expected, which could adversely impact its cash flows and distributions to its unitholders.

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

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

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

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

Enerplus’ indebtedness may limit the timing or amount of the distributions that the Fund pays to unitholders.

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

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

The amounts available under Enerplus’ credit facility may not be sufficient for future operations, or Enerplus may not be able to obtain additional financing on attractive economic terms, if at all.  Enerplus’ credit facility is available on a one year revolving basis.  If the lenders do not extend the facility at the end of the annual revolving period, the loan will convert to a two year term loan.  If this occurs, Enerplus may need to obtain alternate financing.  Any failure to obtain suitable replacement financing may have a material adverse effect on Enerplus’ business, and distributions to unitholders may be materially reduced.

44

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

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

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

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

Enerplus is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs.  In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms.  Accordingly, Enerplus’ properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons.

Enerplus does not establish a separate reclamation fund for the purpose of funding its estimated future environmental and reclamation obligations.  Enerplus cannot assure prospective investors that it will be able to satisfy its future environmental and reclamation obligations.  Any site reclamation or abandonment costs incurred in the ordinary course in a specific period will be funded out of cash flows and, therefore, will reduce the amounts available for distribution to unitholders.  Should Enerplus be unable to fully fund the cost of remedying an environmental claim, Enerplus might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

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

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

If Enerplus expands operations beyond oil and natural gas production in western Canada, Enerplus may face new challenges and risks.  If Enerplus is unsuccessful in managing these challenges and risks, its results of operations and financial condition could be adversely affected.

Enerplus’ operations and expertise are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin.  In the future, Enerplus may acquire oil and natural gas properties outside this geographic area.  In addition, the Trust Indenture does not limit Enerplus’ activities to oil and natural gas production and development, and Enerplus could acquire other energy related assets, such as oil and natural gas processing plants or pipelines.  Expansion of Enerplus’ activities into new areas may present challenges and risks

45

that it has not faced in the past.  If Enerplus does not manage these challenges and risks successfully, its results of operations and financial condition could be adversely affected.

Delays in business operations could adversely affect the Fund’s distributions to unitholders.

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of Enerplus’ properties, and the delays of those operators in remitting payment to Enerplus, payments between any of these parties may also be delayed by:

•restrictions imposed by lenders;

•accounting delays;

•delays in the sale or delivery of products;

•delays in the connection wells to a gathering system;

•blowouts or other accidents;

•adjustments for prior periods;

•recovery by the operator of expenses incurred in the operation of the properties; or

•the establishment by the operator of reserves for these expenses.

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

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

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

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

Unitholders are entirely dependent on the management of Enerplus with respect to the acquisition of oil and natural gas properties and assets, the development and acquisition of additional reserves, the management and administration of all matters relating to Enerplus’ properties and the administration of the Fund.  The loss of the services of key individuals could have a detrimental effect on the Fund.  Investors should carefully consider whether they are willing to rely on the management of Enerplus before investing in the Trust Units.

46

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

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

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

Under Canadian accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” that is based, in part, upon estimated future net cash flows from reserves.  If the net capitalized costs exceed this limit, Enerplus must charge the amount of the excess against earnings.  If oil and natural gas prices decline, Enerplus’ net capitalized cost may exceed this cost ceiling, ultimately resulting in a charge against its earnings.  Under United States generally accepted accounting principles (“GAAP”), the cost ceiling is generally lower than under Canadian GAAP because the future net cash flows used in the United States ceiling test are discounted to a present value.  Accordingly, Enerplus would have more risk of a ceiling test write-down in a declining price environment if Enerplus reported under United States GAAP.  While these write-downs would not affect cash flow, the charge to earnings could be viewed unfavourably in the market.

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

From time to time, Enerplus conducts title reviews in accordance with industry practice prior to purchases of resource assets. However, if conducted, these reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat Enerplus’ title to the purchased assets.  If this type of defect were to occur, Enerplus’ entitlement to the production and reserves from the purchased assets could be jeopardized and, as a result, distributions to unitholders may be reduced.

Risks Related to Enerplus’ Structure and the Ownership of the Trust Units

Changes in tax and other laws may adversely affect unitholders.

Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource allowance, may in the future be changed or interpreted in a manner that adversely affects the Fund and its unitholders. For instance, certain proposed amendments to the Tax Act announced in the Canadian federal government’s 2004 budget may affect the permitted amount of non-Canadian resident ownership of the Trust Units and may result in increased withholding tax on the Fund’s cash distributions paid to non-residents of Canada. See “General Development of Enerplus Resources Fund – Recent Developments – Non-Resident Ownership, Mutual Fund Trust Status and Impact of 2004 Canadian Federal Government Budget Proposals”. In particular, the proposed transition period within which Enerplus may be required to take certain steps to ensure that it “not be maintained primarily for the benefit of non-residents” of Canada (as defined in the Tax Act), currently proposed to end on January 1, 2007, may be shortened or eliminated.

Whether or not the transition period is shortened or eliminated, Enerplus may not be able to take steps necessary to ensure that the Fund “not be maintained primarily for the benefits of non-residents” within the prescribed transition period, if any, and to ensure that the Fund maintains its mutual fund trust status (as further discussed below). Even if the Fund is successful in taking such measures, there can be no assurance that such measures will be completed in a manner that is not detrimental to unitholders, including both non-resident unitholders and the unitholders as a whole. Additionally, legislation may be implemented to limit the investment in income funds and royalty trusts by certain investors or to change the manner in which these entities are taxed. Tax authorities having jurisdiction over Enerplus or the unitholders may disagree with how Enerplus calculates its income for tax purposes or could change administrative practices to Enerplus’ detriment or the detriment of its unitholders.

47

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

Enerplus intends that the Fund will continue to qualify as a mutual fund trust for purposes of the Tax Act.  The Fund may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status.  See “– Changes in tax and other laws may adversely affect unitholders” above and “General Development of Enerplus Resources Fund – Recent Developments – Non-Resident Ownership, Mutual Fund Trust Status and Impact of 2004 Canadian Federal Government Budget Proposals”.  Should the status of the Fund as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Fund and its unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

•The Fund would be taxed on certain types of income distributed to unitholders, including income generated by the royalties held by the Fund. Payment of this tax may have adverse consequences for some unitholders, particularly unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax.

•The Fund would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust.

•Trust Units held by unitholders that are not residents of Canada would become taxable Canadian property.  These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them.

•Trust Units would not constitute qualified investments for registered retirement savings plans (“RRSPs”), registered retirement income funds (“RRIFs”), registered education savings plans (“RESPs”) or deferred profit sharing plans (“DPSPs”).  If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to 1% of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan.  An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units.  If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Customs and Revenue Agency.

•The Fund would no longer be exempt from the application of the alternative minimum tax provisions of the Tax Act.

In addition, Enerplus may take certain measures in the future to the extent it believes necessary to ensure that the Fund maintains its status as a mutual fund trust.  These measures could be adverse to certain holders of Trust Units, particularly “non-residents” of Canada (as defined in the Tax Act).  See “Description of the Trust Units and the Trust Indenture –  Non-Resident Ownership Provisions.”

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

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in Enerplus.  The Trust Units represent an equal fractional beneficial interest in the Fund and, as such, the ownership of the Trust Units does not provide unitholders with the statutory rights normally associated with ownership of shares of a corporation, including, for example, the right to bring “oppression” or “derivative” actions.  The unavailability of these statutory rights may also reduce the ability of the Fund’s unitholders to seek legal remedies against other parties on Enerplus’ behalf.

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

48

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

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

The limited liability of the Fund’s unitholders is uncertain.

Because of uncertainties in the law relating to investment trusts, there is a risk that a unitholder could be held personally liable for obligations of the Fund in respect of contracts or undertakings which the Fund enters into and for certain liabilities arising otherwise than out of contracts including claims in tort, claims for taxes and possibly certain other statutory liabilities.  Although it is intended that every written contract or commitment of the Fund will contain an express disavowal of liability of the unitholders and a limitation of liability to Fund property, such protective provisions may not operate to avoid unitholder liability.  Notwithstanding Enerplus’ attempts to limit unitholder liability, unitholders may not be protected from liabilities of the Fund to the same extent that a shareholder is protected from the liabilities of a corporation.  Further, although the Fund has agreed to indemnify and hold harmless each unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a unitholder resulting from or arising out of the unitholder not having limited liability, Enerplus cannot assure prospective investors that any assets would be available in these circumstances to reimburse unitholders for any such liability.  However, personal liability to unitholders of a trust in Canada is minimal where the beneficiaries are not controlling the day-to-day activities of the trust and there is no direct contact between the beneficiaries of the trust and parties who contract with the trust, each of which conditions is satisfied in the case of the Fund and its unitholders. Legislation that would limit trust unitholder liability has been proposed or discussed in certain jurisdictions of Canada but such legislation has not yet been passed and there is no assurance that such legislation will be passed in any jurisdiction or be enacted in a manner that will eliminate all risk of unitholder liability.

The redemption rights of unitholders is limited.

Unitholders have a limited right to require the Fund to repurchase Trust Units, which is referred to as a redemption right.  See “Description of the Trust Units and the Trust Indenture - Redemption Right”.  It is anticipated that the redemption right will not be the primary mechanism for unitholders to liquidate their investment.  The Fund’s ability to pay cash in connection with a redemption is subject to limitations.  Any securities which may be distributed in specie to unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities.  In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

49

Risks Particular to United States and Other Non-Resident Unitholders

In addition to the risk factors set forth above (and in particular those set forth under “Risks Related to Enerplus’ Structure and the Ownership of the Trust Units – Changes in tax and other laws may adversely affect unitholders”), the following risk factors are particular to unitholders who are not residents of Canada.

United States unitholders may be subject to passive foreign investment company rules.

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

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

The Canadian Tax Act and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the cash distributions or other property paid by the Fund to unitholders who are not residents of Canada, and these taxes may change from time to time. In particular, a proposal contained in the Canadian federal government’s 2004 budget would result in a 15% withholding tax being applied to return of capital portion of distributions made to non-resident unitholders after 2004. See “Recent Developments – Non-Resident Ownership, Mutual Fund Trust Status and Impact of 2004 Canadian Federal Government Budget Proposals”.

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

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

50

SELECTED CONSOLIDATED FINANCIAL INFORMATION

The following table sets forth selected consolidated financial information of Enerplus for the past three years.

	Year Ended December 31,
	2003		2002		2001
	(in $ thousands, except per Trust Unit amounts)
Gross oil and gas sales	$	935,819	$	630,167	$	589,312
Net income	249,600		115,876		180,269
Per Trust Unit – Basic	2.90		1.61		3.28
Per Trust Unit – Diluted	2.89		1.61		3.28
Cash available for distribution	379,055		246,787		316,454
Per Trust Unit	4.32		3.32		5.67
Capital expenditures (net)	145,151		203,639		152,216
Total assets	2,615,612		2,471,631		2,284,253
Long term debt	338,117		361,729		412,589

The above financial data has been taken from the audited consolidated financial statements of the Fund for the years ended December 31, 2003, 2002 and 2001.  The audited consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles.  See Note 1 to the Fund’s audited annual consolidated financial statements for the year ended December 31, 2003 for a description of the significant accounting policies of the Fund.

Cash Distributions to Unitholders

Reference is made to the information under the heading “Distributions to Unitholders” in this Annual Information Form.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis of financial results for the year ended December 31, 2003, as contained on pages 54 to 76 of the Fund’s Annual Report for the year ended December 31, 2003, is incorporated by reference in this Annual Information Form.

51

MARKET FOR SECURITIES

The Trust Units are listed and posted for trading on the Toronto Stock Exchange (the “TSX”) and the New York Stock Exchange (the “NYSE”).  The trading symbol for the Trust Units on the TSX is “ERF.UN” and on the NYSE is “ERF”.

The following table sets forth certain trading information for the Trust Units on the TSX in 2003.

Month	High		Low		Close		Volume
January	$	29.00	$	27.66	$	28.77	2,989,801
February	29.12		26.15		28.62		2,579,126
March	29.12		25.82		28.15		3,629,745
April	28.75		27.07		28.68		3,001,059
May	32.98		28.47		32.85		5,389,507
June	34.10		27.25		31.28		6,654,795
July	34.09		31.00		34.09		6,464,418
August	36.70		33.70		36.48		3,967,781
September	37.10		30.75		35.25		4,209,308
October	37.09		35.12		35.82		3,352,752
November	37.10		35.62		36.15		3,941,580
December	40.72		36.15		39.35		5,620,527

DIRECTORS AND OFFICERS

Directors of EnerMark

The directors of EnerMark are nominated by the unitholders of the Fund at each annual meeting of unitholders.  All directors serve until the next annual meeting or until a successor is elected or appointed.  The name, municipality of residence, principal occupation for the past five years, year of appointment as a director of EnerMark and the number of Trust Units beneficially owned, directly or indirectly, or over which control or direction is exercised for each director of EnerMark are set forth below:

Name and Residence	Director Since	Principal Occupation for Past Five Years(9)
André Bineau (2)(3) Montréal, Québec, Canada	February 1996	Vice President of Association de bienfaisance et de retraite des policiers et policières de la Ville de Montréal (a municipal pension plan).
Derek J.M. Fortune (3)(4)(6) Ottawa, Ontario, Canada	June 2001	Chairman of DF Consulting and Financial Services Inc. (a private consulting firm) since 2003. Prior thereto, Secretary/Manager, City of Ottawa Superannuation Fund (a municipal pension plan).
Gordon J. Kerr (9) Calgary, Alberta, Canada	May 2001	President and Chief Executive Officer of Enerplus since May 2001 (and Chief Financial Officer of Enerplus until December 2001).  Prior thereto, Executive Vice President and Chief Financial Officer of Enerplus since January 2001.  Prior thereto, Senior Vice President, Financial Services of Enerplus since September 2000.  Prior thereto, Vice President, Finance and Chief Financial Officer of Enerplus since 1998.
Douglas R. Martin (1)(4)(7) Calgary, Alberta, Canada	July 2000	President of Charles Avenue Capital Corp. (a private merchant banking company) since April 2000. Prior thereto, Chairman of the Board of Pursuit Resources Corp. (an oil and natural gas exploration and production company).
Robert Normand (2)(4)(6) Rosemere, Québec, Canada	June 2001	Corporate director.

52

Name and Residence	Director Since	Principal Occupation for Past Five Years(9)
Eric P. Tremblay (9) Calgary,Alberta, Canada	January 2001	Senior Vice President, Capital Markets of Enerplus since September 2000.  Prior thereto, Senior Vice President, Corporate Development of Enerplus since January 2000.  Prior thereto, Vice President, Corporate Development of Enerplus since 1996.
Donald T. West (5) Calgary, Alberta, Canada	April 2003	Businessman since October 1999.  Prior thereto, President and Chief Executive Officer of Rigel Energy Corporation (an oil and natural gas exploration and production company).
Harry B. Wheeler (2)(5) Calgary, Alberta, Canada	January 2001	President of Colchester Investments Ltd. (a private investment firm) since January 2001.  Prior thereto, Chairman of the Board of Cabre Exploration Ltd. (an oil and natural gas exploration and production company).
Robert L. Zorich(3)(8) Houston, Texas, USA	January 2001	Managing Director of EnCap Investments L.P. (a private firm that provides private equity financing to the oil and gas industry).

Notes:

(1)Chairman of the board of directors and ex officio member of all committees of the board of directors.

(2)The Audit and Risk Management Committee is comprised of Robert Normand as Chairman, André Bineauand Harry B. Wheeler. Mr. Bineauis not standing for re-election as a director of EnerMark at the 2004 annual general meeting and the resulting vacancy on this committee will be filled by the directors following that meeting.

(3)The Corporate Governance, Nominating and Environment, Health & Safety Committee is comprised of Robert L. Zorich as Chairman, Derek J.M. Fortune and André Bineau. Mr. Bineauis not standing for re-election as a director of EnerMark at the 2004 annual general meeting and the resulting vacancy on this committee will be filled by the directors following that meeting.

(4)The Compensation and Human Resources Committee is comprised of Douglas R. Martin as interim Chairman, Robert Normand and Derek J. M. Fortune.

(5)The Reserves Committee is comprised of Harry B. Wheeler and Donald T. West.

(6)Prior to the merger of Enerplus and EnerMark Income Fund on June 21, 2001, each of Derek J.M. Fortune and Robert Normand was a director of Enerplus Resources Corporation (“ERC”), the entity responsible for governance of Enerplus prior to the merger.  Mr. Fortune was a director of ERC since June 1992 and Mr. Normand was a director of ERC since March 1998.

(7)From 1991 to 2000, Mr. Martin was director of Coho Energy, Inc. (“Coho”), an oil and natural gas corporation that was listed on the TSE and NASDAQ.  In 1999, Coho filed for protection under United States federal bankruptcy law, from which it was released in April, 2000.  The directors of Coho were not held responsible for any actions.  Mr. Martin resigned as a director of Coho in April of 2000.

(8)In late 1997, Mr. Zorich was appointed to the board of directors of Benz Energy Inc. (“Benz”), a Vancouver Stock Exchange (now TSX Venture Exchange) listed company at the time, as a representative of Mr. Zorich’s employer, EnCap Investments L.L.C., which had provided certain financing to Benz.  On November 8, 2000, Benz, together with its wholly-owned subsidiary, Texstar Petroleum Inc., jointly filed a petition for protection under United States federal bankruptcy law, and on January 19, 2001, the shares of Benz were made subject to a cease trade order by the Alberta Securities Commission and suspended from trading on the Canadian Venture Exchange Inc. for failing to file required financial information.

(9)Prior to the completion of the acquisition of EGEM by Enerplus on April 23, 2003, the executive services of Enerplus Resources Fund were provided by EGEM (and its predecessor, Enerplus Energy Services Ltd. (“EES”)), pursuant to a management agreement.  All references to Enerplus in the above table prior to April 23, 2003 should be construed as references to EGEM or EES, but for simplicity, Enerplus has been utilized throughout the above table.

Officers of EnerMark

The name, municipality of residence, position held, principal occupation for the past five years, year of appointment as an officer of EnerMark and the number of Trust Units beneficially owned, directly or indirectly, or over which control or direction is exercised for each officer of EnerMark are set out below:

Name and Residence	Office	Principal Occupation for Past Five Years(1)
Gordon J. Kerr Calgary, Alberta, Canada	President and Chief Executive Officer	President and Chief Executive Officer of Enerplus since May 2001 (and Chief Financial Officer of Enerplus until December 2001).  Prior thereto, Executive Vice President and Chief Financial Officer of Enerplus since January 2001.  Prior thereto, Senior Vice President, Financial Services of Enerplus since September 2000.  Prior thereto, Vice President, Finance and Chief Financial Officer of Enerplus since 1998.

53

Name and Residence	Office	Principal Occupation for Past Five Years(1)
Heather J. Culbert Calgary, Alberta, Canada	Senior Vice President, Corporate Services	Senior Vice President, Corporate Services of Enerplus since March 2001.  Prior thereto, Vice President, Management Information Systems & Administration of Enerplus since 1996.
Garry A. Tanner Calgary, Alberta, Canada	Senior Vice President and Chief Operating Officer	Senior Vice President and Chief Operating Officer of Enerplus since February 2003.  Prior thereto, Senior Vice President, New Business Development of EGEM since August 2001 (in addition to Senior Vice President of El Paso Merchant Energy (a merchant trading company) since October 2000).  Prior thereto, Senior Vice President of EnCap Investments L.L.C. (a private firm that provides private equity financing to the oil and gas industry) since 1997.
Eric P. Tremblay Calgary, Alberta, Canada	Senior Vice President, Capital Markets	Senior Vice President, Capital Markets of Enerplus since September 2000.  Prior thereto, Senior Vice President, Corporate Development of Enerplus since January 2000.  Prior thereto, Vice President, Corporate Development of Enerplus since 1996.
Robert J. Waters Calgary, Alberta, Canada	Senior Vice President and Chief Financial Officer	Senior Vice President and Chief Financial Officer of Enerplus since December 2001.  Prior thereto, Vice President, Finance and Chief Financial Officer of Pengrowth Corporation (a subsidiary of an oil and gas income trust) since June 1998.
Jo-Anne M. Caza Calgary, Alberta, Canada	Vice President, Investor Relations	Vice President of Investor Relations of Enerplus since September 2000. Prior thereto, Manager, Investor Relations of Enerplus since 1998.
Daryl W. Cook Calgary, Alberta, Canada	Vice President, Operations	Vice President, Operations of Enerplus since 1997.
Ian C. Dundas Calgary, Alberta, Canada	Vice President and Director, Business Development	Vice President and Director, Business Development of Enerplus since February 2003. Prior thereto, Vice President of EGEM since August 2001.  Prior thereto, Chief Financial Officer of Medmira Inc., (a public biotechnology company) since 1999.  Prior thereto, Director of Enron Canada Corp. merchant banking group since 1996.
Wayne T. Foch Calgary, Alberta, Canada	Vice President, Finance	Vice President, Finance of Enerplus since February 2001.  Prior thereto, Treasurer of EMR Resource Management Ltd. (the management company of EnerMark Income Fund) since April 1996.
David A. McCoy Calgary, Alberta, Canada	General Counsel & Corporate Secretary	General Counsel & Corporate Secretary of Enerplus since December 2002.  Prior thereto, Consultant, Offshore & International Operations, with EnCana Corporation (an oil and gas exploration and production company) since 2002.  Prior thereto, Vice President, General Counsel & Governmental Affairs with Conoco Canada Limited since 2000.  Prior thereto, Alberta Counsel with Westcoast Energy Inc. (a regulated pipeline and midstream company) since 1998.
Daniel M. Stevens Calgary, Alberta, Canada	Vice President, Development Services	Vice President, Development Services of Enerplus since February 2003.  Prior thereto, Manager, Drilling and Completions of Enerplus since 1996.

54

Name and Residence	Office	Principal Occupation for Past Five Years(1)
Wayne G. Ford Calgary, Alberta, Canada	Controller, Operations	Controller of Enerplus since August 2001.  Prior thereto, Controller of Argonauts Group Ltd. (an oil and gas exploration and production company) since January 2000.  Prior thereto, Operations Accounting Consultants with Enerplus since September 1998.  Prior thereto, Client Service Manager with Applied Terravision Systems Inc. (a software company) since October 1996.
Rodney D. Gray Calgary, Alberta, Canada	Controller, Finance	Controller, Finance of Enerplus since June 2002.  Prior thereto, independent consultant since September 2001.  Prior thereto, Controller (since 1999) and Manager, Financial Reporting (since 1998) with Berkley Petroleum Corp.
Christina S. Meeuwsen Calgary, Alberta, Canada	Assistant Corporate Secretary	Assistant Corporate Secretary of Enerplus since December 2002.  Prior thereto, Corporate Secretary of Enerplus since 1996.

Note:

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

As of April 16, 2004, the directors and officers named above beneficially own, directly or indirectly, an aggregate of 371,350 Trust Units, representing approximately 0.4% of the outstanding Trust Units.

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

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

To the knowledge of the directors and executive officers of EnerMark, none of the directors or executive officers of EnerMark, or any associate or affiliate of the foregoing, has had any material interest, direct or indirect, in any material transaction with Enerplus since January 1, 2001 or in any proposed transaction that would materially affect Enerplus.

MATERIAL CONTRACTS

The only material contract to which the Fund is a party, other than contracts entered into in the normal course of business, is the Trust Indenture, which is described under “Information Respecting Enerplus Resources Fund - Description of the Trust Units and the Trust Indenture”.  A copy of the Trust Indenture was publicly filed on January 5, 2004 and is available on the Fund’s SEDAR profile at www.sedar.com.

55

INTERESTS OF EXPERTS

Sproule Associates Limited prepared the Sproule Report in respect of the Fund’s oil and natural gas properties, a summary of which is contained in this Annual Information Form.  The auditors of the Fund are Deloitte & Touche LLP, Chartered Accountants, Calgary, Alberta.  As of the date of the Sproule Report, the directors, officers and associates of Sproule, as a group, beneficially owned, directly or indirectly, less than 1% of the Fund’s outstanding Trust Units at such time.  As of March 5, 2004, the date of Deloitte & Touche LLP’s auditors report on the Fund’s consolidated financial statements as at and for the year ended December 31, 2003, the partners of Deloitte & Touche LLP, as a group, did not beneficially own, directly or indirectly, any Trust Units.

REGISTRAR AND TRANSFER AGENT

The registrar and transfer agent for the Trust Units is CIBC Mellon Trust Company, at its principal offices in Calgary, Alberta, Toronto, Ontario and Montréal, Québec.  The co-transfer agent for the Trust Units is Mellon Investor Services LLC in New York, New York.

ADDITIONAL INFORMATION

Additional information relating to the Fund may be found on the Fund’s company profile on the SEDAR website at www.sedar.com.  Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of the Fund’s securities and securities authorized for issuance under equity compensation plans, as applicable, is contained in the Fund’s information circular dated March 17, 2004 for its 2004 annual general meeting of Unitholders.  Furthermore, additional financial information relating to the Fund is provided in the Fund’s audited consolidated financial statements and management’s discussion and analysis for the period ended December 31, 2003.

56

APPENDIX “A”

REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

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

1.We have evaluated and reviewed the Fund’s reserves data as at January 1, 2004. The reserves data consist of the following:

(a)(i)proved and proved plus probable oil and gas reserves estimated as at January 1, 2004 using forecast prices and costs; and

(ii)the related estimated future net revenue; and

(b)(i)proved oil and gas reserves estimated as at January 1, 2004 using constant prices and costs; and

(ii)the related estimated future net revenue.

Although our report is effective January 1, 2004, we confirm that the information contained in our report would be identical if it were presented December 31, 2003, the fiscal year-end of the Fund.

2.The reserves data are the responsibility of the Fund’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Fund evaluated and reviewed by us as of January 1, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Fund’s management and the board of directors of EnerMark Inc.:

Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)
			New Present Value of future Net Revenue (10% discount rate)
			Audited		Evaluated		Reviewed		Total
			(in $ thousands)
Sproule Associates Limited	Effective January 1, 2004 prepared November 2003 to March 2004	Canada	$	Nil	$	1,929,723	$	312,654	$	2,242,377

A-1

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

6.We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.

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

Executed as to our report referred to above:

Sproule Associates Limited	“Hans J. Firla”
Calgary, Alberta, Canada	Hans J. Firla, P. Eng.
April 16, 2004	Project Manager & Associate
	“Michael W. Maughan”
	Michael W. Maughan, C.P.G., P. Geol.
	Manager, Geoscience & Associate
	“Hari M. Kapil”
	Hari M. Kapil, P. Eng.
	Senior Vice-President, Engineering

A-2

APPENDIX “B”

REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION

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

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

(a)(i)proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

(ii)the related estimated future net revenue; and

(b)(i)proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

(ii)the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated and reviewed the Fund’s reserves data. The report of the independent qualified reserves evaluator is presented as Appendix “A” to this Annual Information Form.

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

(a)reviewed EnerMark’s procedures for providing information to the independent qualified reserves evaluator;

(b)met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c)reviewed the reserves data with management and the independent qualified reserves evaluator.

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

(a)the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b)the filing of the report of the independent qualified reserves evaluator on the reserves data; and

(c)the content and filing of this report.

B-1

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

ENERPLUS RESOURCES FUND

By EnerMark Inc.

“Gordon J. Kerr”

Gordon J. Kerr

President and Chief Executive Officer

“Robert J. Waters”

Robert J. Waters

Senior Vice President and

Chief Financial Officer

“Harry B. Wheeler”

Harry B. Wheeler

Director

“Donald T. West”

Donald T. West

Director

April 22, 2004

Enerplus Resources Fund

The Dome Tower

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

Calgary, Alberta, Canada

T2P 2Z1

Telephone:(403) 298-2200

Fax:(403) 298-2211

www.enerplus.com