AIF for the year ended December 31, 2005 dated March 7, 2006

EX-99.1 2 ex991.htm AIF FOR THE YEAR ENDED DECEMBER 31, 2005 DATED MARCH 7, 2006 AIF for the year ended December 31, 2005 dated March 7, 2006

Exhibit 99.1

ANNUAL INFORMATION FORM

For the year ended December 31, 2005

March 7, 2006

TABLE OF CONTENTS

	Page		Page

GLOSSARY OF TERMS	iii	Additional Operational Information	45
ABBREVIATIONS AND CONVERSIONS	v	INFORMATION RESPECTING ENERPLUS RESOURCES FUND	45
PRESENTATION OF ENERPLUS' OIL AND GAS RESERVES AND PRODUCTION INFORMATION	vi	Description of the Trust Units and the Trust Indenture	45
PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION	ix	Description of the Royalty Agreements and Subordinated Notes	52
DESCRIPTION OF DISTRIBUTABLE INCOME	ix	Management and Corporate Governance	53
FORWARD-LOOKING STATEMENTS	ix	Unitholder Rights Plan	53
STRUCTURE OF ENERPLUS RESOURCES FUND	1	DEBT OF ENERPLUS	54
GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND	3	Bank Credit Facility	54
Historical Overview	3	Senior Unsecured Notes	55
Developments in the Past Three Years	3	DISTRIBUTIONS TO UNITHOLDERS	56
OIL AND NATURAL GAS RESERVES	6	Distributable Income	56
Summary of Aggregate Enerplus Reserves	7	Distribution History	56
Summary of Conventional Oil and Natural Gas Reserves	9	U.S. Tax Reporting Matters	57
Summary of Joslyn Project Bitumen Reserves	18	INDUSTRY CONDITIONS	58
Reconciliation of Reserves	21	RISK FACTORS	62
Reconciliation of Changes in Net Present Value of Future Net Revenue	25	MARKET FOR SECURITIES	74
Undeveloped Reserves	26	DIRECTORS AND OFFICERS	75
Proved and Probable Reserves Not on Production	27	INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	78
OPERATIONAL INFORMATION	27	MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS	78
Overview	27	INTERESTS OF EXPERTS	78
Description of Principal Properties and Operations	27	REGISTRAR AND TRANSFER AGENT	78
Summary of Principal Production Locations	37	ADDITIONAL INFORMATION	79
Oil and Natural Gas Wells and Unproved Properties	38	APPENDIX "A" - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	A-1
Exploration and Development Activities	38	APPENDIX "B" - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	B-1
Quarterly Production History	39	APPENDIX "C" - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	C-1
Quarterly Netback History	40	APPENDIX "D" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION	D-1
Abandonment and Reclamation Costs	42	APPENDIX "E" - AUDIT COMMITTEE DISCLOSURE	E-1
Tax Horizon	42
Costs Incurred	42
Marketing Arrangements and Forward Contracts	42
Environment, Health and Safety	43
Impact of Environmental Protection Requirements	44

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."

"AECO" means the physical storage and trading hub for natural gas on the TransCanada Alberta Transmission System (NOVA) which is the delivery point for the various benchmark Alberta index prices.

"bitumen" means a highly viscous crude oil which is too thick to flow in its native state and which cannot be produced without altering its viscosity. The density of bitumen is generally less than 10^o API;

"D&M" means DeGolyer and MacNaughton, independent petroleum consultants;

"D&M Report" means the independent engineering evaluation of Enerplus' U.S. conventional oil, NGLS and natural gas interests prepared by D&M dated January 23, 2006 and effective December 31, 2005, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus' reserves reporting) dated December 31, 2005;

"Deer Creek" means Deer Creek Energy Limited, a wholly owned subsidiary of Total S.A. and the operator of the Joslyn Project;

"ECT" means Enerplus Commercial Trust, a trust organized under the laws of Alberta (the trustee of which is Enerplus ECT Resources Ltd., an Alberta corporation) and an indirect wholly owned subsidiary of the Fund;

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

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

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

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

"Enerplus USA" means Enerplus Resources (USA) Corporation, a corporation organized under the laws of Delaware and an indirect wholly-owned subsidiary of EnerMark;

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

"Fund" means Enerplus Resources Fund;

"GAAP" means generally accepted accounting principles;

"GLJ" means GLJ Petroleum Consultants Ltd., independent petroleum consultants;

"GLJ Report" means the independent engineering evaluation of Enerplus' interest in the Joslyn Project prepared by GLJ dated February 28, 2006 and effective December 31, 2005, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus' reserves reporting) dated December 31, 2005;

"Henry Hub" means the physical storage and trading hub in Louisiana which is the delivery point for the NYMEX natural gas contract;

"Joslyn Project" or the "Project" means the development of Oil Sands Lease #24 located in the Athabasca oil sands fairway of northeastern Alberta;

"Joslyn Lease" means the sections of land contained within Alberta Oil Sands Lease No. 7280060T24 and Alberta Oil Sands Permit No. 7099110070;

iii

"Lyco" means Lyco Energy Corporation, a Delaware corporation which merged with Enerplus Newco LLC on February 9, 2006 and continued as Enerplus USA;

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

"NYMEX" means the New York Mercantile Exchange;

"NYSE" means the New York Stock Exchange;

"Operating Subsidiaries" means the direct and indirect subsidiaries of the Fund that own, acquire and operate oil and natural gas assets for the benefit of the Fund (with the material Operating Subsidiaries being EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA);

"SAGD" means Steam Assisted Gravity Drainage, an in situ production process used to recover bitumen from oil sands;

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

"Sproule Report" means the independent engineering evaluation of Enerplus' Canadian conventional oil, NGLs and natural gas interests prepared by Sproule dated February 28, 2006 and effective December 31, 2005, utilizing commodity price forecasts of Sproule dated December 31, 2005;

"subsidiary" has the meaning assigned thereto in the Securities Act (Alberta);

"Tax Act" means the Income Tax Act (Canada);

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

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

"Trustee" means CIBC Mellon Trust Company, or its successor as trustee of the Fund;

"TSX" means the Toronto Stock Exchange; and

"WTI" means West Texas Intermediate crude oil that serves as the benchmark crude oil for the NYMEX crude oil contract delivered in Cushing, Oklahoma.

ABBREVIATIONS AND CONVERSIONS

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

API American Petroleum Institute

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

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

NGLs natural gas liquids

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

PRESENTATION OF ENERPLUS'

OIL AND GAS RESERVES AND PRODUCTION INFORMATION

Disclosure of Information

In this Annual Information Form, all estimates of oil and natural gas reserves and production are presented on a "company interest" basis (as defined below), unless expressly indicated that they have been presented on a "gross" or "net" basis. "Company interest" is not a term defined or recognized under NI 51-101 and does not have a standardized meaning under NI 51-101. Therefore, the "company interest" reserves of Enerplus may not be comparable to similar measures presented by other issuers, and investors are cautioned that "company interest" reserves should not be construed as an alternative to "gross" or "net" reserves calculated in accordance with NI 51-101.

Enerplus' actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this Annual Information Form. The estimated future net revenue from the production of Enerplus' oil and natural gas reserves does not represent the fair market value of Enerplus' reserves.

The United States Securities and Exchange Commission (the "SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves net of royalties and interests of others that an issuer has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Canadian securities laws permit oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves (each as defined in NI 51-101 and described below), and to disclose reserves and production on a "gross" basis before deducting royalties. Probable Reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than Proved Reserves. Enerplus has prepared this Annual Information Form in accordance with Canadian disclosure requirements, and as a result, Enerplus has disclosed reserves designated as "Probable Reserves" and "Proved plus Probable Reserves". The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. Moreover, Enerplus has determined and disclosed estimated future net revenue from its reserves using both constant and forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report.

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

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

The oil and gas operational and reserves information contained in this Annual Information Form contains the information required to be included in the Statement of Reserves Data and Other Oil and Gas Information pursuant to NI 51-101 adopted by the Canadian securities regulatory authorities and has been prepared and prescribed in accordance with Form 51-101F1. Readers should also refer to the Report on Reserves Data by Sproule attached hereto as Appendix "A", the Report on Reserves Data by GLJ attached hereto as Appendix "B", the Report on Reserves Data by D&M attached as Appendix "C" and the Report of Management and Directors on Oil and Gas Disclosure attached hereto as Appendix "D". The effective date for the Statement of Reserves Data and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2005 and the information contained in the Annual Information Form has been prepared as of March 7, 2006.

Certain of the following definitions and guidelines are contained in Section 5.4 of Volume 1 of the Canadian Oil and Gas Evaluation Handbook (First Edition, June 30, 2002) (the "COGE Handbook") prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the "CIM (Petroleum Society)") and have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society). Readers should consult the COGE Handbook for additional explanation and guidance. Certain other terms used in this Annual Information

Form have the meanings assigned to them in NI 51-101 and accompanying Companion Policy 51-101CP, adopted by the Canadian securities regulatory authorities.

Interests in Reserves, Production, Wells and Properties

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

"gross" means:

(i)

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

(ii)

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

(iii)

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

"net" means:

(i)

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

(ii)

in relation to Enerplus' interest in wells, the number of wells obtained by aggregating Enerplus' working interest in each of its gross wells; and

(iii)

in relation to Enerplus' interest in a property, the total area in which Enerplus has an interest multiplied by the working interest owned by Enerplus.

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

Reserves Categories

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

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

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

Development and Production Status

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

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

•

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

vii

•

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

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

Levels of Certainty for Reported Reserves

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

•

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

•

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

•

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

Description of Price and Cost Assumptions

"Constant prices and costs" means, unless expressly noted otherwise, prices and costs used in an estimate that are:

(i)

Enerplus' prices and costs as at December 31, 2005, 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)

viii

PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION

The financial information included and incorporated by reference in this Annual Information Form has been prepared in accordance with Canadian GAAP. Canadian GAAP differs in some significant respects from U.S. GAAP and therefore this financial information may not be comparable to the financial information of U.S. companies. The principal differences as they apply to the Fund are summarized in Note 15 to the Fund's audited consolidated financial statements for the year ended December 31, 2005.

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

DESCRIPTION OF DISTRIBUTABLE INCOME

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

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains certain forward-looking statements and forward-looking information which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. Enerplus believes the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations will prove to be correct, and such forward-looking statements and information included in this Annual Information Form should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this Annual Information Form and Enerplus does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.

In particular, this Annual Information Form contains forward-looking statements and information pertaining to the following:

•

the quantity of and future net revenues from Enerplus' reserves;

•

oil, NGLs and natural gas production levels;

•

commodity prices, foreign currency exchange rates and interest rates;

•

capital expenditure programs and other expenditures;

•

supply and demand for oil, NGLs and natural gas;

•

expectations regarding Enerplus' ability to raise capital and to continually add to reserves through acquisitions and development;

•

schedules and timing of certain projects and Enerplus' strategy for growth;

•

Enerplus' future operating and financial results; and

•

treatment under governmental and other regulatory regimes and tax, environmental and other laws.

Enerplus' actual results could differ materially from those anticipated in these forward-looking statements and information as a result of both known and unknown risks, including the risk factors set forth under "Risk Factors" in this Annual Information Form and those set forth below:

•

volatility in market prices for oil, NGLs and natural gas;

•

changes or fluctuations in oil, NGLs and natural gas production levels;

•

changes in foreign currency exchange rates and interest rates;

•

changes in capital and other expenditure requirements and debt service requirements;

•

liabilities and unexpected events inherent in oil and gas operations, including geological, technical, drilling and processing problems;

•

uncertainties associated with estimating reserves;

•

competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

•

incorrect assessments of the value of acquisitions;

•

Enerplus' success at acquisition, exploitation and development of reserves;

•

changes in general economic, market and business conditions in Canada, North America and worldwide;

•

actions by governmental or regulatory authorities including changes in income tax laws (including those relating to mutual fund trusts or investment eligibility) or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; and

•

changes in environmental or other legislation applicable to Enerplus' operations, and Enerplus' ability to comply with current and future environmental and other laws.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in Enerplus' management's discussion and analysis for the year ended December 31, 2005, which is available through the internet on Enerplus' SEDAR profile at www.sedar.com. Readers are also referred to the risk factors described in this Annual Information Form under "Risk Factors" and in other documents Enerplus files from time to time with securities regulatory authorities. Copies of these documents are available without charge from Enerplus or electronically on the internet on Enerplus' SEDAR profile at www.sedar.com or Enerplus' website at www.enerplus.com.

ENERPLUS RESOURCES FUND

Annual Information Form

For the year ended December 31, 2005

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, unsecured debt issued by EnerMark to the Fund and 95%, 99% and 99% royalties on the crude oil and natural gas property interests of EnerMark, ERC and Enerplus Oil & Gas, respectively. The head, principal and registered office of Enerplus is located at The Dome Tower, Suite 3000, 333 - 7th Avenue S.W., Calgary, Alberta, T2P 2Z1. Enerplus also has a U.S. office located at Wells Fargo Center, Suite 1300, 1700 Lincoln Street, Denver, Colorado, 80203. The Trustee of the Fund is CIBC Mellon Trust Company located at The Dome Tower, Suite 600, 333 - 7th Avenue S.W., Calgary, Alberta T2P 2Z1. The board of directors of EnerMark is responsible for the governance of Enerplus.

The Fund's primary focus is to maintain and enhance monthly cash distributions to its unitholders from the net cash flow generated by the operation and development of its Operating Subsidiaries' existing crude oil and natural gas properties and the strategic acquisition and rationalization of properties and assets. See "Operational Information - Overview".

Operating Subsidiaries

The Fund's direct and indirect Operating Subsidiaries acquire, exploit and operate crude oil and natural gas assets 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. The Fund's material Operating Subsidiaries are EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA.

Each of EnerMark, ERC and Enerplus Oil & Gas are corporations organized under the Business Corporations Act (Alberta). ECT is a trust organized under the laws of Alberta, and Enerplus USA is a corporation organized under the laws of Delaware. All of the issued and outstanding common shares of EnerMark are directly owned by the Fund and all of the trust units of ECT are indirectly owned by the Fund through its wholly owned subsidiary, Enerplus Limited Partnership II (an Alberta limited partnership). All of the issued and outstanding common shares of ERC are owned by EnerMark and all of the issued and outstanding common shares of Enerplus Oil & Gas are owned by ERC. All of the shares of Enerplus USA are indirectly owned by EnerMark.

Organization Chart

The simplified organizational structure of Enerplus, including the material Operating Subsidiaries of the Fund and the flow of funds from those Operating Subsidiaries to the Fund and from the Fund to its unitholders, is set forth below:

GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND

Historical Overview

Enerplus Resources Fund was formed in 1986. The Fund's Trust Units are currently traded on the TSX under the symbol "ERF.UN" and on the NYSE under the symbol "ERF". The Fund was historically one of a group of royalty trusts, income funds and other entities managed by companies within the Enerplus organization.

Developments in the Past Three Years

Acquisition of PCC Energy Inc. and PCC Energy Corp.

On March 5, 2003, Enerplus acquired all of the outstanding shares of PCC Energy Inc. and PCC Energy Corp. (collectively, "PCC"), which were wholly owned Canadian subsidiaries of U.S. based PetroCorp Incorporated, for total cash consideration of $165.8 million. Enerplus also assumed a working capital deficiency of $1.1 million. A portion of the PCC properties acquired are subject to a royalty arrangement structured as a net profits interest ("NPI") with a private U.S. company. The NPI is accounted for as a working interest of the U.S. company in these properties and as a result is not included in Enerplus' reserves, production, or financial information.

Management Internalization Transaction

On April 23, 2003, following receipt of unitholder approval, Enerplus acquired all of the outstanding shares of EGEM from an indirect wholly owned subsidiary of El Paso and incurred associated costs for a total cash consideration of $55.1 million. Prior to the acquisition, EGEM received management fees from Enerplus for providing administrative and management services to the Fund and its operating subsidiaries pursuant to a management agreement. As part of this transaction, EGEM agreed to fix the total fees payable under the management agreement from January 1, 2003 to April 23, 2003 at $3.0 million. Immediately following completion of the transaction, EGEM assigned and transferred all of its rights and obligations under the management agreement to EnerMark (a wholly owned subsidiary of the Fund), and the management agreement was effectively terminated.

Acquisition of Ice Energy Limited

On January 7, 2004, Enerplus completed the acquisition of all of the issued and outstanding shares of Ice Energy Limited. Enerplus previously owned approximately 12.7% of the shares of Ice Energy Limited which were acquired in a prior transaction. Total consideration for all of the Ice Energy Limited shares, including those previously owned by Enerplus, was $121.2 million. Enerplus also assumed a working capital deficiency of $9.3 million. As a result of this acquisition, Enerplus acquired an interest in the Shackleton area of western Saskatchewan. 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.

Participation in Joslyn Project and Other Oil Sands Projects

In 2002, Enerplus acquired a 16% working interest in the Joslyn Project. The remaining 84% working interest is owned by Deer Creek, which was acquired by Total S.A., a major international oil and gas company, in 2005. Deer Creek is the operator of the Joslyn Project. For a description of the status and operations of the Joslyn Project, see "Operational Information - Description of Principal Properties and Operations - Oil Sands".

In early 2006, Enerplus sold a 1% working interest in the Joslyn Project in exchange for equity in Laricina Energy Ltd., a new private oil sands focused company led by the former Chief Executive Officer of Deer Creek prior to its acquisition by Total S.A. Included in the sale is an area of mutual interest agreement which has been designed to jointly pursue additional in-situ oil sands ventures.

Acquisition of Properties from ChevronTexaco Corporation

On June 30, 2004, Enerplus completed the acquisition of conventional oil and natural gas interests located in western Canada from ChevronTexaco Corporation for total consideration of approximately $467.2 million. The acquired production was weighted approximately 46% to natural gas and 54% to crude oil and NGLs and the acquisition also provided Enerplus with approximately 99,200 gross (45,400 net) acres of undeveloped land. The acquired properties were located in the Brooks area of southern Alberta, the Chinchaga area of northwestern Alberta, the Mitsue area of north central Alberta as well as in southeastern Saskatchewan and southwestern Manitoba.

Unitholder Limited Liability Legislation

Effective July 1, 2004 the Income Trusts Liability Act (Alberta) was proclaimed in force. The Act creates a statutory limitation on the liability of unitholders of income trusts organized under the laws of Alberta, such as the Fund. The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after the legislation comes into effect. The legislation does not affect the liability of unitholders with respect to any act, default, obligation or liability that arose before July 1, 2004. Additionally, in December 2004 Ontario adopted unitholder limited liability legislation similar to that implemented in Alberta. The Province of Québec historically had codified limited liability for trust unitholders. For additional information, see "Risk Factors - Risks Related to Enerplus' Structure and the Ownership of the Trust Units - The limited liability of the Fund's unitholders is uncertain".

Acquisition of TriLoch Resources Inc.

On July 1, 2005, Enerplus completed the acquisition of TriLoch Resources Inc. ("TriLoch"). Pursuant to a plan of arrangement, Enerplus issued 1,632,516 Trust Units in exchange for all of the shares of TriLoch. The Trust Unit value of $42.32 was based upon the weighted average price of the Fund's Trust Units on the TSX during the five day trading period surrounding the announcement of the transaction on May 17, 2005. Total consideration was approximately $77.4 million consisting of Trust Units, transaction costs and the retirement of TriLoch's bank indebtedness. Enerplus also assumed a working capital deficiency of $0.4 million. The TriLoch acquisition complemented Enerplus' existing asset base in the Enchant area of southern Alberta. Production from the area was weighted approximately 68% to natural gas and 32% to crude oil and NGLs at the time of the acquisition.

Acquisition of Lyco Energy Corporation and Sleeping Giant LLC

On August 30, 2005, Enerplus acquired all of the outstanding shares, and retired the debt (including mandatory redeemable preferred shares) of Lyco Energy Corporation ("Lyco"), a private Delaware corporation operating in the states of Montana and North Dakota. The total consideration paid for Lyco was approximately $501.9 million and Enerplus also assumed a working capital deficiency of $4.4 million. In connection with the acquisition, the Fund issued 10,637,500 Trust Units (issued upon the automatic conversion of subscription receipts upon the closing of the Lyco transaction) at a price of $46.25 for gross proceeds of $492.0 million (net proceeds of $466.9 million). Production from the Lyco properties was weighted approximately 92% light oil and 8% natural gas at the time of the acquisition. These properties predominantly produce high quality Middle Bakken light oil from the Sleeping Giant project area. The acquisition also provided Enerplus with approximately 120,000 net acres of undeveloped land in both Montana and North Dakota.

On October 4, 2005, Enerplus completed the acquisition of Sleeping Giant LLC, a private U.S. company. Total consideration paid for Sleeping Giant LLC was approximately $111.9 million and was financed through existing credit facilities. Enerplus also assumed positive working capital of $4.4 million. The assets of Sleeping Giant LLC consisted of additional working interests in the Sleeping Giant light crude oil project in Montana that formed part of the earlier Lyco acquisition. This acquisition increased Enerplus' working interest in certain producing wells in the Sleeping Giant project to an approximate 70% working interest.

Sleeping Giant LLC was subsequently merged with Lyco, and on February 9, 2006 Lyco merged with Enerplus Newco LLC and continued as Enerplus Resources (USA) Corporation.

The Lyco and Sleeping Giant LLC acquisitions were Enerplus' first acquisitions of U.S. assets. On February 21, 2006 Enerplus opened an office in Denver, Colorado to support the ongoing operation of its assets in Montana and North Dakota and to facilitate future growth in the United States.

Federal Government Pronouncements on Income Trusts and Mutual Fund Trust Status

Throughout 2004 and much of 2005, the Canadian federal government expressed concerns about a potential reduction in future tax revenues due to the increased presence of income trusts in the Canadian economy and the increased ownership of income trusts and other flow-through entities by non-residents of Canada. The former Canadian Minister of Finance indicated in the February 23, 2005 federal budget that further consultations would be pursued with stakeholders on taxation issues related to income trusts and other flow-through entities. On September 8, 2005, the Canadian Department of Finance released a discussion paper on these matters and invited interested parties to make submissions to the Department of Finance. On November 23, 2005, the former Canadian Minister of Finance issued a news release announcing that no change would be made to the tax treatment of income trusts in Canada and calling an end to the consultation process initiated in September 2005. In the January 2006 federal election, the Canadian federal Liberal government was replaced by a Conservative government. Both the Liberal and Conservative parties have stated they do not intend to change the current tax treatment of income trusts. In connection with the November 23, 2005 announcement, the former Liberal government also announced a reduction in the personal tax rate on corporate dividends received by Canadians in order to "level the playing field" between corporations and income trusts. The new Conservative government has not made any statement in respect of the proposed personal tax rate reduction.

Enerplus believes the November 23, 2005 announcement should help to remove some of the uncertainty surrounding the taxation of the income trust sector. However, the Fund continues to rely on an exception contained in the Tax Act in order to ensure that it maintains its "mutual fund trust" status under the Tax Act. Absent such exception, the high percentage of Trust Unit ownership by non-residents of Canada (approximately 73% in February 2006) may cause the Fund to be considered to be "established or maintained primarily for the benefit of non-residents of Canada", and as a result the Fund would lose its mutual fund trust status. See "Risk Factors - Risks Related to Enerplus' Structure and the Ownership of the Trust Units".

S&P/TSX Index Inclusion

The increased presence and importance of the income trust sector in Canadian financial markets, together with the removal of the legislative uncertainty regarding unitholder limited liability in certain provinces described above under "-- Unitholder Limited Liability Legislation", led Standard and Poor's to include income trusts, including Enerplus, in the S&P/TSX Composite Index. Income trusts were given one-half of their respective weightings in the S&P/TSX Composite Index in December 2005 with the remaining one-half weighting to occur in mid-March 2006.

OIL AND NATURAL GAS RESERVES

Overview

All of Enerplus' reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. Sproule Associates Limited, a firm of independent petroleum engineers based in Calgary, Alberta, has evaluated properties which comprise approximately 89% of the net present value (discounted at 10%, using forecast prices and costs) of Enerplus' Proved plus Probable Canadian conventional oil and natural gas reserves. Enerplus has evaluated the balance of the Canadian conventional properties using similar evaluation parameters, including the same forecast price, inflation and exchange rates assumptions utilized by Sproule. Sproule has reviewed Enerplus' evaluation of these properties.

DeGolyer and MacNaughton, independent petroleum consultants based in Dallas, Texas, has evaluated all of Enerplus' conventional oil and natural gas reserves located in the United States. For internal consistency in Enerplus' reserves reporting, D&M has used Sproule's forecast prices, inflation and exchange rates.

GLJ Petroleum Consultants Ltd., a private independent petroleum consulting firm based in Calgary, Alberta, has evaluated all of Enerplus' interests in the SAGD-recoverable bitumen reserves of the Joslyn Project, again using the same forecast price, inflation and exchange rates assumptions utilized by Sproule.

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

The following tables summarize, as at December 31, 2005, Enerplus' oil, NGLs and natural gas reserves and the estimated net present values of future net cash revenues associated with such reserves, together with certain information, estimates and assumptions associated with such reserve estimates. The data contained in the tables is a summary of the evaluations, and as a result the tables may contain slightly different numbers than the evaluations themselves due to rounding. Additionally, the numbers in the tables may not add due to rounding.

All future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures, and both before and after income taxes. The future net revenues have been prepared on the basis that no cash income taxes will be paid by Enerplus in the future in Canada. Enerplus' U.S. operations are subject to cash income taxes, and as a result Enerplus' U.S. reserves are shown net of the taxes Enerplus estimates will be payable after taking into account inter-company debt within Enerplus' structure. See "Operational Information - Tax Horizon". The estimated net present value of future net revenue does not include the Alberta Royalty Tax Credit. With respect to pricing information in the following reserves information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and the differing costs of service applied by various purchasers. The natural gas liquids prices were adjusted to reflect historical average prices received.

It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of Enerplus' crude oil, NGLs and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in "Presentation of Enerplus' Oil and Gas Reserves and Production Information" in conjunction with the following tables and notes.

Summary of Aggregate Enerplus Reserves

The following tables summarize the aggregate company interest reserves volumes and net present value of future net revenue contained in the Sproule Report relating to Enerplus' Canadian conventional crude oil and natural gas reserves, the D&M Report relating to Enerplus' U.S. conventional crude oil and natural gas reserves and the GLJ Report relating to Enerplus' interest in the SAGD-recoverable bitumen reserves of the Joslyn Project, all based on Sproule's forecast price and cost assumptions. Detailed separate summaries of the Sproule Report, the D&M Report and the GLJ Report, including certain assumptions incorporated into those reports, and presentation of Enerplus' oil and gas reserves in accordance with NI 51-101 are contained in the tables following the summary report below.

Summary of Aggregate Oil and Gas Reserves

As of December 31, 2005

Company Interest Reserves,

Forecast Prices and Costs

	OIL AND NATURAL GAS RESERVES
RESERVES CATEGORY	Light & Medium Oil		Heavy Oil		Bitumen		Total Oil		Natural Gas Liquids		Natural Gas		Total
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mmcf)		(MBOE)
Proved Developed Producing
Canada		69,768		30,583		-		100,351		11,644		771,428		240,566
United States		15,773		-		-		15,773		-		8,794		17,239
Total		85,541		30,583		-		116,124		11,644		780,222		257,805

Proved Developed Non-Producing
Canada		163		-		-		163		475		19,468		3,884
United States		-		-		-		-		-		-		-
Total		163		-		-		163		475		19,468		3,884

Proved Undeveloped
Canada		3,318		2,318		9,453		15,089		965		161,728		43,008
United States		7,822		-		-		7,822		-		4,358		8,548
Total		11,140		2,318		9,453		22,911		965		166,086		51,556

Total Proved
Canada		73,249		32,901		9,453		115,603		13,084		952,624		287,458
United States		23,595		-		-		23,595		-		13,152		25,787
Total		96,844		32,901		9,453		139,198		13,084		965,776		313,245

Probable
Canada		17,498		8,495		43,700		69,693		3,539		309,572		124,827
United States		5,574		-		-		5,574		-		32,946		11,065
Total		23,072		8,495		43,700		75,267		3,539		342,518		135,892

Total Proved plus Probable
Canada		90,747		41,396		53,153		185,296		16,623		1,262,196		412,285
United States		29,169		-		-		29,169		-		46,098		36,852
Total		119,916		41,396		53,153		214,465		16,623		1,308,294		449,137

Summary of Aggregate Net Present Value

of Future Net Revenue Attributable to Oil and Gas Reserves

As of December 31, 2005

Company Interest Reserves,

Forecast Prices and Costs

	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
	Before Deducting Income Taxes											After Deducting Income Taxes
RESERVES CATEGORY	0%		5%		10%		15%		20%			0%		5%		10%		15%		20%
	(in $ millions)
CONVENTIONAL OIL AND GAS RESERVES
Proved Developed Producing
Canada		6,991		4,800		3,789		3,199		2,807			6,991		4,800		3,789		3,199		2,807
United States		745		605		510		442		391			620		500		419		360		316
Total		7,736		5,405		4,299		3,641		3,198			7,611		5,300		4,208		3,559		3,123

Proved Developed Non-Producing
Canada		107		81		65		57		48			107		81		65		57		48
United States		-		-		-		-		-			-		-		-		-		-
Total		107		81		65		57		48			107		81		65		57		48

Proved Undeveloped
Canada		687		501		380		296		236			687		501		380		296		236
United States		299		225		175		140		114			180		133		102		82		67
Total		986		726		555		436		350			867		634		482		378		303

Total Proved
Canada		7,785		5,382		4,234		3,552		3,091			7,785		5,382		4,234		3,552		3,091
United States		1,044		830		685		582		505			800		633		521		442		383
Total Proved Conventional Reserves		8,829		6,212		4,919		4,134		3,596			8,585		6,015		4,755		3,994		3,474

Probable
Canada		2,376		1,121		695		495		384			2,376		1,121		695		495		384
United States		453		257		162		111		80			308		174		108		72		51
Total Probable Conventional Reserves		2,829		1,378		857		606		464			2,684		1,295		803		567		435
Total Proved Plus Probable Conventional Reserves		11,658		7,590		5,776		4,740		4,060			11,269		7,310		5,558		4,561		3,909

BITUMEN RESERVES
Proved Undeveloped		38		19		9		3		-			38		19		9		3		-
Probable		299		88		27		6		(4	)		299		88		27		6		(4	)
Total Proved Plus Probable Bitumen Reserves		337		107		36		9		(4	)		337		107		36		9		(4	)
TOTAL CONVENTIONAL AND BITUMEN RESERVES		11,995		7,697		5,812		4,749		4,056			11,606		7,417		5,594		4,570		3,905

Summary of Conventional Oil and Natural Gas Reserves

The following tables and notes summarize the reserves volumes and net present value of future net revenue attributable to Enerplus' conventional oil and gas reserves, including certain assumptions relating to the determination of those reserves and values. All information relating to Canadian conventional reserves is contained in the Sproule Report and all information relating to United States conventional reserves is contained in the D&M Report.

Summary of Conventional Oil and Gas Reserves

As of December 31, 2005

Forecast Prices and Costs

	OIL AND NATURAL 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)		(Mmcf)		(Mmcf)		(Mmcf)
Proved Developed Producing
Canada		69,768		69,076		63,384		30,583		30,556		27,399		771,428		746,984		618,640
United States		15,773		15,773		13,261		-		-		-		8,794		8,794		7,393
Total		85,541		84,849		76,645		30,583		30,556		27,399		780,222		755,778		626,033

Proved Developed Non-Producing
Canada		163		164		142		-		-		-		19,468		19,258		15,466
United States		-		-		-		-		-		-		-		-		-
Total		163		164		142								19,468		19,258		15,466

Proved Undeveloped
Canada		3,318		3,281		2,901		2,318		2,318		1,966		161,728		156,197		132,094
United States		7,822		7,822		6,554		-		-		-		4,358		4,358		3,651
Total		11,140		11,103		9,455		2,318		2,318		1,966		166,086		160,555		135,745

Total Proved Reserves
Canada		73,249		72,521		66,427		32,901		32,874		29,365		952,624		922,439		766,200
United States		23,595		23,595		19,815		-		-		-		13,152		13,152		11,044
Total		96,844		96,116		86,242		32,901		32,874		29,365		965,776		935,591		777,244

Probable Reserves
Canada		17,498		17,272		14,967		8,495		8,487		6,131		309,572		301,586		252,478
United States		5,574		5,574		4,673		-		-		-		32,946		32,946		27,655
Total		23,072		22,846		19,640		8,495		8,487		6,131		342,518		334,532		280,133

Total Proved Plus Probable Reserves
Canada		90,747		89,793		81,394		41,396		41,361		35,496		1,262,196		1,224,025		1,018,678
United States		29,169		29,169		24,488		-		-		-		46,098		46,098		38,699
Total		119,916		118,962		105,882		41,396		41,361		35,496		1,308,294		1,270,123		1,057,377

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(continued)

	OIL AND NATURAL GAS RESERVES
	NATURAL GAS LIQUIDS						TOTAL
RESERVES CATEGORY	Company Interest		Gross		Net		Company Interest		Gross		Net
	(Mbbls)		(Mbbls)		(Mbbls)		(MBOE)		(MBOE)		(MBOE)
Proved Developed Producing
Canada		11,644		11,465		8,095		240,566		235,595		201,985
United States		-		-		-		17,239		17,239		14,493
Total		11,644		11,465		8,095		257,805		252,834		216,478

Proved Developed Non-Producing
Canada		475		473		331		3,884		3,846		3,050
United States		-		-		-		-		-		-
Total		475		473		331		3,884		3,846		3,050

Proved Undeveloped
Canada		965		963		681		33,555		32,595		27,564
United States		-		-		-		8,548		8,548		7,163
Total		965		963		681		42,103		41,143		34,727

Total Proved Reserves
Canada		13,084		12,901		9,107		278,005		272,036		232,599
United States		-		-		-		25,787		25,787		21,656
Total		13,084		12,901		9,107		303,792		297,823		254,255

Probable Reserves
Canada		3,539		3,480		2,470		81,127		79,503		65,648
United States		-		-		-		11,065		11,065		9,282
Total		3,539		3,480		2,470		92,192		90,568		74,930

Total Proved Plus Probable Reserves
Canada		16,623		16,381		11,577		359,132		351,539		298,247
United States		-		-		-		36,852		36,852		30,938
Total		16,623		16,381		11,577		395,984		388,391		329,185

Summary of Net Present Value of Future Net Revenue

Attributable to Conventional Oil and Gas Reserves

As of December 31, 2005

Forecast Prices and Costs

	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
	Before Deducting Income Taxes										After Deducting Income Taxes
RESERVES CATEGORY	0%		5%		10%		15%		20%		0%		5%		10%		15%		20%
	(in $ millions)
Proved Developed Producing
Canada		6,991		4,800		3,789		3,199		2,807		6,991		4,800		3,789		3,199		2,807
United States		745		605		510		442		391		620		500		419		360		316
Total		7,736		5,405		4,299		3,641		3,198		7,611		5,300		4,208		3,559		3,123

Proved Developed Non-Producing
Canada		107		81		65		57		48		107		81		65		57		48
United States		-		-		-		-		-		-		-		-		-		-
Total		107		81		65		57		48		107		81		65		57		48

Proved Undeveloped
Canada		687		501		380		296		236		687		501		380		296		236
United States		299		225		175		140		114		180		133		102		82		67
Total		986		726		555		436		350		867		634		482		378		303

Total Proved
Canada		7,785		5,382		4,234		3,552		3,091		7,785		5,382		4,234		3,552		3,091
United States		1,044		830		685		582		505		800		633		521		442		383
Total		8,829		6,212		4,919		4,134		3,596		8,585		6,015		4,755		3,994		3,474

Probable
Canada		2,376		1,121		695		495		384		2,376		1,121		695		495		384
United States		453		257		162		111		80		308		174		108		72		51
Total		2,829		1,378		857		606		464		2,684		1,295		803		567		435

Total Proved plus Probable
Canada		10,161		6,503		4,929		4,047		3,475		10,161		6,503		4,929		4,047		3,475
United States		1,497		1,087		847		693		585		1,108		807		629		514		434
Total		11,658		7,590		5,776		4,740		4,060		11,269		7,310		5,558		4,561		3,909

Summary of Conventional Oil and Gas Reserves

As of December 31, 2005

Constant Prices and Costs

	OIL AND NATURAL 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)		(Mmcf)		(Mmcf)		(Mmcf)
Proved Developed Producing
Canada		71,318		70,626		64,862		30,634		30,608		27,452		794,051		769,331		637,078
United States		15,883		15,883		13,354		-		-		-		8,852		8,852		7,442
Total		87,201		86,509		78,216		30,634		30,608		27,452		802,903		778,183		644,520

Proved Developed Non-Producing
Canada		169		168		146		-		-		-		19,772		19,562		15,747
United States		-		-		-		-		-		-		-		-		-
Total		169		168		146		-		-		-		19,772		19,562		15,747

Proved Undeveloped
Canada		3,355		3,319		2,935		2,364		2,363		2,004		164,320		158,738		133,899
United States		7,858		7,858		6,583		-		-		-		4,378		4,378		3,667
Total		11,213		11,177		9,518		2,364		2,363		2,004		168,698		163,116		137,566

Total Proved Reserves
Canada		74,842		74,113		67,943		32,998		32,971		29,456		978,143		947,631		786,724
United States		23,741		23,741		19,937		-		-		-		13,230		13,230		11,109
Total		98,583		97,854		87,880		32,998		32,971		29,456		991,373		960,861		797,833

Probable Reserves
Canada		17,649		17,422		15,111		8,570		8,562		6,197		316,239		308,162		257,853
United States		5,501		5,501		4,613		-		-		-		33,042		33,042		27,736
Total		23,150		22,923		19,724		8,570		8,562		6,197		349,281		341,204		285,589

Total Proved Plus Probable Reserves
Canada		92,491		91,535		83,054		41,568		41,533		35,653		1,294,382		1,255,793		1,044,577
United States		29,242		29,242		24,550		-		-		-		46,272		46,272		38,845
Total		121,733		120,777		107,604		41,568		41,533		35,653		1,340,654		1,302,065		1,083,422

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(continued)

	OIL AND NATURAL GAS RESERVES
	NATURAL GAS LIQUIDS						TOTAL
RESERVES CATEGORY	Company Interest		Gross		Net		Company Interest		Gross		Net
	(Mbbls)		(Mbbls)		(Mbbls)		(MBOE)		(MBOE)		(MBOE)

Proved Developed Producing
Canada		11,899		11,718		8,256		246,193		241,174		206,750
United States		-		-		-		17,358		17,358		14,594
Total		11,899		11,718		8,256		263,551		258,532		221,344

Proved Developed Non-Producing
Canada		475		474		332		3,939		3,902		3,102
United States		-		-		-		-		-		-
Total		475		474		332		3,939		3,902		3,102

Proved Undeveloped
Canada		966		965		682		34,072		33,103		27,938
United States		-		-		-		8,588		8,588		7,194
Total		966		965		682		42,659		41,691		35,132

Total Proved Reserves
Canada		13,340		13,157		9,270		284,204		278,180		237,790
United States		-		-		-		25,946		25,946		21,789
Total		13,340		13,157		9,270		310,150		304,126		259,578

Probable Reserves
Canada		3,562		3,504		2,483		82,488		80,848		66,767
United States		-		-		-		11,008		11,008		9,236
Total		3,562		3,504		2,483		93,496		91,856		76,002

Total Proved Plus Probable Reserves
Canada		16,902		16,661		11,753		366,691		359,028		304,556
United States		-		-		-		36,954		36,954		31,024
Total		16,902		16,661		11,753		403,645		395,982		335,580

Summary of Net Present Value of Future Net Revenue

Attributable to Conventional Oil and Gas Reserves

As of December 31, 2005

Constant Prices and Costs

	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
	Before Deducting Income Taxes										After Deducting Income Taxes
RESERVES CATEGORY	0%		5%		10%		15%		20%		0%		5%		10%		15%		20%
	(in $ millions)
Proved Developed Producing
Canada		8,206		5,500		4,224		3,480		2,987		8,206		5,500		4,224		3,480		2,987
United States		861		685		568		485		424		685		544		450		384		334
Total		9,067		6,185		4,792		3,965		3,411		8,891		6,044		4,674		3,864		3,321

Proved Developed Non-Producing
Canada		130		97		77		64		55		130		97		77		64		55
United States		-		-		-		-		-		-		-		-		-		-
Total		130		97		77		64		55		130		97		77		64		55

Proved Undeveloped
Canada		980		711		530		406		319		980		711		530		406		319
United States		358		267		206		164		132		223		167		129		102		83
Total		1,338		978		736		570		451		1,203		878		659		508		402

Total Proved
Canada		9,316		6,308		4,831		3,950		3,361		9,316		6,308		4,831		3,950		3,361
United States		1,219		952		774		649		556		908		711		579		486		417
Total		10,535		7,260		5,605		4,599		3,917		10,224		7,019		5,410		4,436		3,778

Probable
Canada		2,724		1,320		821		581		442		2,724		1,320		821		581		442
United States		539		309		196		134		97		356		199		122		81		57
Total		3,263		1,629		1,017		715		539		3,080		1,519		943		662		499

Total Proved plus Probable
Canada		12,040		7,628		5,652		4,531		3,803		12,040		7,628		5,652		4,531		3,803
United States		1,758		1,261		970		783		653		1,264		910		701		567		474
Total		13,798		8,889		6,622		5,314		4,456		13,304		8,538		6,353		5,098		4,277

Forecast Prices and Costs

	CRUDE OIL										NATURAL GAS					NATURAL GAS LIQUIDS
																Edmonton Par Price
Year	WTI Cushing Oklahoma			Edmonton Par Price 40º API			Hardisty Heavy 12º API		Cromer Medium 29.3º API		30 day spot @ AECO		Henry Hub Price			Propanes			Butanes			Pentanes Plus			Inflation Rate		Exchange Rate
	($US/bbl)			($Cdn/bbl)			($Cdn/bbl)		($Cdn/bbl)		($Cdn/mmbtu)		($US/mmbtu)			($Cdn/bbl)			($Cdn/bbl)			($Cdn/bbl)			(%/year)		($US/$Cdn)
2006		60.81			70.07			37.07		59.62		11.58		11.59			39.25			47.01			71.77			2.5		0.85
2007		61.61			70.99			37.29		60.39		10.84		10.11			39.76			47.62			72.71			2.5		0.85
2008		54.60			62.73			34.23		53.48		8.95		8.50			35.14			42.08			64.25			2.5		0.85
2009		50.19			57.53			32.27		49.18		7.87		7.58			32.22			38.59			58.92			1.5		0.85
2010		47.76			54.65			31.15		46.75		7.57		7.32			30.61			36.66			55.97			1.5		0.85
Thereafter		1.5	%		1.5	%		⁽¹⁾		⁽¹⁾		⁽¹⁾		1.5	%		1.5	%		1.5	%		1.5	%		1.5		0.85

___________

Note:

(1)	Escalation varies after 2010

In 2005, Enerplus received a weighted average price (net of transportation costs but before hedging) of $41.99/bbl for heavy crude oil, $61.96/bbl for light and medium crude oil, $47.33/bbl for NGLs and $8.41/Mcf for natural gas.

Constant Prices and Costs

The constant price and cost case assumes the continuance of product prices at December 31, 2005 and operating costs projected for 2006, 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$0.85 and the following prices in effect as at December 31, 2005:

CRUDE OIL

NATURAL GAS

NATURAL GAS LIQUIDS

Edmonton Par Price

Year

WTI

Cushing Oklahoma

Edmonton

Par Price

40º API

Hardisty

Heavy

12º API

Cromer

Medium

29.3º API

30 day spot

@ AECO

Henry Hub

Price

Propanes

Butanes

Pentanes

Plus

Inflation

Rate

Exchange

Rate

($US/bbl)

($Cdn/bbl)

($Cdn/mmbtu)

($US/mmbtu)

($Cdn/bbl)

(%/year)

($US/$Cdn)

2006

61.04

68.12

30.86

52.28

9.99

10.08

51.90

59.32

71.35

0.85

Undiscounted Future Net Revenue by Reserves Category

The undiscounted total future net revenue by reserves category as of December 31, 2005, using both constant and forecast prices and costs, is set forth below:

RESERVES CATEGORY	Revenue		Royalties		Operating Costs		Development Costs		Abandonment and Reclamation Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
	(in $ millions)
Constant Prices and Costs
Proved Reserves
Canada		16,230		2,870		3,573		364		107		9,316		-		9,316
United States		1,808		411		88		84		6		1,219		311		908
Total		18,038		3,281		3,661		448		113		10,535		311		10,224

Proved Plus Probable Reserves
Canada		20,872		3,786		4,520		416		110		12,040		-		12,040
United States		2,571		590		117		100		6		1,758		494		1,264
Total		23,443		4,376		4,637		516		116		13,798		494		13,304

Forecast Prices and Costs
Proved Reserves
Canada		14,856		2,399		4,139		378		155		7,785		-		7,785
United States		1,601		363		100		86		8		1,044		244		800
Total		16,457		2,762		4,239		464		163		8,829		244		8,585

Proved Plus Probable Reserves
Canada		19,474		3,232		5,475		432		174		10,161		-		10,161
United States		2,277		520		147		103		10		1,497		389		1,108
Total		21,751		3,752		5,622		535		184		11,658		389		11,269

Net Present Value of Future Net Revenue by Reserves Category

The net present value of future net revenue before income taxes by reserves category and production group as of December 31, 2005, using both constant and forecast prices and costs and discounted at 10% per year, is set forth below:

		Future Net Revenue Before Income Taxes (Discounted at 10%/year)
RESERVES CATEGORY	Production Group	Constant Prices and Costs		Forecast Prices and Costs
		(in $ millions)
Canada
Proved Reserves	Light and Medium Crude Oil ^(a)		1,157		1,023
	Heavy Oil		301		352
	Natural Gas ^(b)		3,373		2,859
Proved Plus Probable Reserves	Light and Medium Crude Oil ^(a)		1,309		1,158
	Heavy Oil		328		383
	Natural Gas ^(b)		4,015		3,388

United States
Proved Reserves	Light and Medium Crude Oil ^(a)		698		612
	Heavy Oil		-		-
	Natural Gas ^(b)		76		73
Proved Plus Probable Reserves	Light and Medium Crude Oil ^(a)		736		633
	Heavy Oil		-		-
	Natural Gas ^(b)		234		214

___________

Notes:

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

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

Estimated Production for Estimates of Future Net Revenue

The volume of gross production from Proved plus Probable Reserves estimated for 2006 in preparing the estimated net present values of future net revenue is set forth below. Canadian production has been estimated by Sproule and U.S. production has been estimated by D&M.

	Canada						United States
Product Type	Aggregate Estimated 2006 Production			Daily Estimated 2006 Production			Aggregate Estimated 2006 Production			Daily Estimated 2006 Production

Crude oil
Light and medium crude oil		5,904	Mbbls		16,174	bbl/d		3,876	Mbbls		10,619	bbl/d
Heavy oil		3,661	Mbbls		10,031	bbl/d	-			-
Total crude oil		9,565	Mbbls		26,205	bbl/d		3,876	Mbbls		10,619	bbl/d
Natural gas liquids		1,504	Mbbls		4,122	bbl/d	-			-
Total liquids		11,069	Mbbls		30,327	bbl/d		3,876	Mbbls		10,619	bbl/d
Natural gas		105,816	MMcf		289,907	Mcf/d		2,555	MMcf		7,001	Mcf/d
Total		28,705	MBOE		78,645	BOE/d		4,302	MBOE		11,786	BOE/d

Future Development Costs

The amount of development costs deducted in the estimation of net present value of future net revenue is as follows (see also "Operational Information - Exploration and 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)
CANADA
2006		161		154		184		175		161		154		184		175
2007		72		62		82		71		74		64		84		73
2008		46		36		54		43		49		38		57		45
2009		31		22		36		26		33		24		39		28
2010		16		10		19		13		18		11		21		14
Remainder		38		19		41		19		43		21		47		22
Total		364		303		416		347		378		312		432		357

UNITED STATES
2006		71		67		79		76		72		69		81		78
2007		13		12		21		18		14		11		22		19
2008		-		-		-		-		-		-		-		-
2009		-		-		-		-		-		-		-		-
2010		-		-		-		-		-		-		-		-
Remainder		-		-		-		-		-		-		-		-
Total		84		79		100		94		86		80		103		97

Summary of Joslyn Project Bitumen Reserves

The following tables summarize the reserves volumes and net present value of future net revenue attributable to Enerplus' 16% working interest in the SAGD-recoverable bitumen reserves of the Joslyn Project as of December 31, 2005, including certain assumptions relating to the determination of those reserves and values, as contained in the GLJ Report. Subsequent to December 31, 2005, Enerplus reduced its economic interest in the Joslyn Project to 15%, as described in "General Development of Enerplus Resources Fund - Developments in the Past Three Years - Participation in Joslyn Project and Other Oil Sands Projects."

Summary of Enerplus' Interest in the SAGD Bitumen Reserves of the

Joslyn Lease and Net Present Values of Future Net Revenue

As of December 31, 2005

Forecast Prices and Costs

	BITUMEN RESERVES				NET PRESENT VALUE OF FUTURE NET REVENUE, BEFORE AND AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
RESERVES CATEGORY	Gross		Net		0%		5%		10%		15%		20%
	(Mbbls)		(Mbbls)		(in $ millions)
Proved Undeveloped Reserves		9,453		9,358		38		19		9		3		0
Probable Reserves		43,700		41,150		299		88		27		6		(4	)
Total Proved Plus Probable		53,153		50,508		337		107		36		9		(4	)

Constant Prices and Costs

	BITUMEN RESERVES				NET PRESENT VALUE OF FUTURE NET REVENUE, BEFORE AND AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
RESERVES CATEGORY	Gross		Net		0%		5%			10%			15%			20%
	(Mbbls)		(Mbbls)		(in $ millions)
Proved Undeveloped Reserves		9,308		9,215		7		(1	)		(4	)		(6	)		(7	)
Probable Reserves		43,845		43,407		117		27			0			(9	)		(13	)
Total Proved Plus Probable Reserves		53,153		52,622		124		26			(4	)		(15	)		(20	)

Forecast Prices and Costs

The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves was based on an inflation rate of 2.5% per year until 2008 and 1.5% per year thereafter, an exchange rate of Cdn$1.00=US$0.85 and the price forecasts set forth below supplied by Sproule as at December 31, 2005 (but utilized by GLJ for internal consistency in Enerplus' reserves reporting). The forecast net prices for bitumen produced from the Joslyn Project ("Joslyn Bitumen") are calculated by subtracting blending costs, transportation and quality differentials from the forecast prices for Bow River Medium crude oil for the relevant periods.

	CRUDE OIL												NATURAL GAS
Year	WTI Cushing Oklahoma			Edmonton Par Price 40º API			Bow River Medium			Joslyn Bitumen			AECO 30 Day Spot Price
	($US/bbl)			($Cdn/bbl)			($Cdn/bbl)			($Cdn/bbl)			($Cdn/MMBTU)
2006		60.81			70.07			47.27			27.78			11.58
2007		61.61			70.99			47.79			28.08			10.84
2008		54.60			62.73			43.23			23.49			8.95
2009		50.19			57.53			40.28			20.77			7.87
2010		47.76			54.65			38.65			20.40			7.57
Thereafter		1.5	%		1.5	%		⁽¹	⁾		⁽¹	⁾		⁽¹	⁾

___________

Note:

(1)	Escalation varies after 2010.

Constant Prices and Costs

The constant price and cost case assumes the continuance of product prices at December 31, 2005 and operating costs projected for 2006, and the continuance of current laws and regulations. In accordance with Canadian Securities Administrators Staff Notice 51-315, the constant price of bitumen produced from the Joslyn Project ("Joslyn Bitumen") was calculated by deducting the 2005 average price differential of a barrel of WTI crude oil and a barrel of Joslyn Bitumen from the December 31, 2005 price for a barrel of WTI crude oil of US$61.04/bbl. Product prices have not been escalated beyond this date nor have operating and capital costs been increased on an inflationary basis. The future net revenue to be received from the production of the reserves was based on an exchange rate of Cdn$1.00=US$0.85 and the following prices in effect as at December 31, 2005:

CRUDE OIL

NATURAL GAS

WTI

Cushing Oklahoma

Edmonton

Par Price

40º API

Bow River

Medium

Joslyn

Bitumen

AECO 30 Day

Spot Price

($US/bbl)

($Cdn/bbl)

($Cdn/MMBTU)

61.04

68.12

44.28

21.24

9.99

Undiscounted Future Net Revenue by Reserves Category

The undiscounted total future net revenue by reserves category as of December 31, 2005, using both constant and forecast prices and costs, is set forth below:

RESERVES CATEGORY	Revenue		Royalties		Operating Costs		Development Costs		Abandonment and Reclamation Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
	(in $ millions)
Constant Prices and Costs
Proved Undeveloped Reserves		198		2		147		41		1		7		0		7
Probable Reserves		931		9		607		195		3		117		0		117
Total Proved Plus Probable Reserves		1,129		11		754		236		4		124		0		124

Forecast Prices and Costs
Proved Undeveloped Reserves		229		2		143		45		1		38		0		38
Probable Reserves		1,321		85		678		254		5		299		0		299
Total Proved Plus Probable Reserves		1,550		87		821		299		6		337		0		337

Net Present Value of Future Net Revenue by Reserves Category

The net present value of future net revenue by reserves category and production group as of December 31, 2005, using both constant and forecast prices and costs and discounted at 10% per year, is set forth below:

		Future Net Revenue Before Income Taxes (Discounted at 10%/year)
RESERVES CATEGORY	Production Group	Constant Prices and Costs			Forecast Prices and Costs
		(in $ millions)
Proved Undeveloped Reserves	Bitumen		(4	)		9
Probable Reserves	Bitumen		0			27
Total Proved Plus Probable Reserves	Bitumen		(4	)		36

Estimated Production for Estimates of Future Net Revenue

The volume of gross production from the Proved plus Probable Reserves in 2006 estimated by GLJ in preparing the estimated net present values of future net revenue is as follows:

Product Type		Aggregate Estimated 2006 Production			Daily Estimated 2006 Production
Bitumen			270 Mbbls			739 bbl/d

Future Development Costs

The amount of development costs deducted in the estimation of net present value of future net revenue is as follows (see also "Operational Information - Exploration and Development Activities"):

	Constant Prices and Costs
	Proved Reserves				Proved Plus Probable Reserves
Year	Undiscounted		Discounted at 10%/year		Undiscounted		Discounted at 10%/year
	(in $ millions)
2006		5		5		11		11
2007		11		11		32		11
2008		-		-		8		6
2009		-		-		-		-
2010		-		-		5		3
Remainder		25		10		180		57
Total		41		26		236		88

	Forecast Prices and Costs
	Proved Reserves				Proved Plus Probable Reserves
Year	Undiscounted		Discounted at 10%/year		Undiscounted		Discounted at 10%/year
	(in $ millions)
2006		5		5		11		11
2007		11		11		33		11
2008		-		-		9		7
2009		-		-		-		-
2010		-		-		6		4
Remainder		29		12		240		66
Total		45		28		299		99

Reconciliation of Reserves

The following tables reconcile Enerplus' oil and natural gas reserves (on both a company interest and net reserves basis) from December 31, 2004 to December 31, 2005, using forecast prices and costs.

Reconciliation of Company Interest Reserves

CANADA	Light and Medium Crude Oil									Heavy Oil									Bitumen
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, 2004		73,039			17,180			90,219			31,369			9,603			40,972			-		47,747			47,747
Acquisitions		1,899			1,075			2,974			-			-			-			-		-			-
Divestments		(1,297	)		(780	)		(2,077	)		(1,343	)		(808	)		(2,151	)		-		-			-
Discoveries		103			34			137			-			-			-			-		-			-
Extensions		238			(25	)		213			38			20			58			-		-			-
Technical Revisions		(1,966	)		(1,808	)		(3,774	)		1,400			(610	)		790			9,453		(4,047	)		5,406
Economic Factors		4,368			1,441			5,809			1,694			468			2,162			-		-			-
Improved Recovery		3,280			381			3,661			2,976			(178	)		2,798			-		-			-
Production		(6,415	)		-			(6,415	)		(3,233	)		-			(3,233	)		-		-			-
December 31, 2005		73,249			17,498			90,747			32,901			8,495			41,396			9,453		43,700			53,153

CANADA (continued)	Natural Gas Liquids									Associated and Non-Associated Gas (Natural Gas)									Total
Factors	Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable
	(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(MMcf)			(MBOE)			(MBOE)			(MBOE)
December 31, 2004		12,776			3,292			16,068			971,598			295,698			1,267,296			279,117			127,105			406,222
Acquisitions		49			14			63			13,609			5,951			19,560			4,216			2,081			6,297
Divestments		(59	)		(40	)		(99	)		(15,614	)		(7,911	)		(23,525	)		(5,301	)		(2,947	)		(8,248	)
Discoveries		7			(1	)		6			2,887			568			3,455			591			127			718
Extensions		724			143			867			36,671			14,322			50,993			7,112			2,525			9,637
Technical Revisions		874			(54	)		820			(16,995	)		(16,860	)		(33,855	)		6,930			(9,329	)		(2,399	)
Economic Factors		353			159			512			20,889			7,541			28,430			9,896			3,325			13,221
Improved Recovery		71			26			97			39,134			10,263			49,397			12,849			1,940			14,789
Production		(1,711	)		-			(1,711	)		(99,555	)		-			(99,555	)		(27,952	)		-			(27,952	)
December 31, 2005		13,084			3,539			16,623			952,624			309,572			1,262,196			287,458			124,827			412,285

UNITED STATES	Light and Medium Crude Oil								Heavy Oil						Bitumen
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, 2004		-			-		-			-		-		-		-		-		-
Acquisitions		23,900			5,041		28,941			-		-		-		-		-		-
Divestments		-			-		-			-		-		-		-		-		-
Discoveries		-			-		-			-		-		-		-		-		-
Extensions		-			-		-			-		-		-		-		-		-
Technical Revisions		747			533		1,280			-		-		-		-		-		-
Economic Factors		-			-		-			-		-		-		-		-		-
Improved Recovery		-			-		-			-		-		-		-		-		-
Production		(1,052	)		-		(1,052	)		-		-		-		-		-		-
December 31, 2005		23,595			5,574		29,169			-		-		-		-		-		-

(continues on next page)

UNITED STATES (continued)	Natural Gas Liquids						Associated and Non-Associated Gas (Natural Gas)								Total
Factors	Proved		Probable		Proved Plus Probable		Proved			Probable		Proved Plus Probable			Proved			Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)			(MMcf)		(MMcf)			(MBOE)			(MBOE)		(MBOE)
December 31, 2004		-		-		-		-			-		-			-			-		-
Acquisitions		-		-		-		12,784			32,779		45,563			26,031			10,504		36,535
Divestments		-		-		-		-			-		-			-			-		-
Discoveries		-		-		-		-			-		-			-			-		-
Extensions		-		-		-		-			-		-			-			-		-
Technical Revisions		-		-		-		946			167		1,113			904			561		1,465
Economic Factors		-		-		-		-			-		-			-			-		-
Improved Recovery		-		-		-		-			-		-			-			-		-
Production		-		-		-		(578	)		-		(578	)		(1,148	)		-		(1,148	)
December 31, 2005		-		-		-		13,152			32,946		46,098			25,787			11,065		36,852

TOTAL ENERPLUS	Light and Medium Crude Oil									Heavy Oil									Bitumen
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, 2004		73,039			17,180			90,219			31,369			9,603			40,972			-		47,747			47,747
Acquisitions		25,799			6,116			31,915			-			-			-			-		-			-
Divestments		(1,297	)		(780	)		(2,077	)		(1,343	)		(808	)		(2,151	)		-		-			-
Discoveries		103			34			137			-			-			-			-		-			-
Extensions		238			(25	)		213			38			20			58			-		-			-
Technical Revisions		(1,219	)		(1,275	)		(2,494	)		1,400			(610	)		790			9,453		(4,047	)		5,406
Economic Factors		4,368			1,441			5,809			1,694			468			2,162			-		-			-
Improved Recovery		3,280			381			3,661			2,976			(178	)		2,798			-		-			-
Production		(7,467	)		-			(7,467	)		(3,233	)		-			(3,233	)		-		-			-
December 31, 2005		96,844			23,072			119,916			32,901			8,495			41,396			9,453		43,700			53,153

TOTAL ENERPLUS (continued)	Natural Gas Liquids									Associated and Non-Associated Gas (Natural Gas)									Total
Factors	Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable
	(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(MMcf)			(MBOE)			(MBOE)			(MBOE)
December 31, 2004		12,776			3,292			16,068			971,598			295,698			1,267,296			279,117			127,105			406,222
Acquisitions		49			14			63			26,393			38,730			65,123			30,247			12,585			42,832
Divestments		(59	)		(40	)		(99	)		(15,614	)		(7,911	)		(23,525	)		(5,301	)		(2,947	)		(8,248	)
Discoveries		7			(1	)		6			2,887			568			3,455			591			127			718
Extensions		724			143			867			36,671			14,322			50,993			7,112			2,525			9,637
Technical Revisions		874			(54	)		820			(16,049	)		(16,693	)		(32,742	)		7,834			(8,768	)		(934	)
Economic Factors		353			159			512			20,889			7,541			28,430			9,896			3,325			13,221
Improved Recovery		71			26			97			39,134			10,263			49,397			12,849			1,940			14,789
Production		(1,711	)		-			(1,711	)		(100,133	)		-			(100,133	)		(29,100	)		-			(29,100	)
December 31, 2005		13,084			3,539			16,623			965,776			342,518			1,308,294			313,245			135,892			449,137

Reconciliation of Net Reserves

CANADA	Light and Medium Crude Oil									Heavy Oil									Bitumen
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, 2004		66,272			14,892			81,164			26,971			8,264			35,235			-		43,640			43,640
Acquisitions		1,349			897			2,246			-			-			-			-		-			-
Divestments		(1,099	)		(778	)		(1,877	)		(1,205	)		(702	)		(1,907	)		-		-			-
Discoveries		84			27			111			-			-			-			-		-			-
Extensions		202			(21	)		181			33			20			53			-		-			-
Technical Revisions		(1,789	)		(1,556	)		(3,345	)		1,136			(441	)		695			9,358		(2,490	)		6,868
Economic Factors		3,814			1,190			5,004			1,312			349			1,661			-		-			-
Improved Recovery		2,939			316			3,255			3,759			(1,359	)		2,400			-		-			-
Production		(5,345	)		-			(5,345	)		(2,641	)		-			(2,641	)		-		-			-
December 31, 2005		66,427			14,967			81,394			29,365			6,131			35,496			9,358		41,150			50,508

CANADA (continued)	Natural Gas Liquids									Associated and Non-Associated Gas (Natural Gas)									Total
Factors	Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable
	(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(MMcf)			(MBOE)			(MBOE)			(MBOE)
December 31, 2004		8,942			2,318			11,260			778,610			243,208			1,021,818			231,953			109,649			341,602
Acquisitions		31			10			41			9,731			4,493			14,224			3,002			1,656			4,658
Divestments		(49	)		(29	)		(78	)		(10,546	)		(5,603	)		(16,149	)		(4,111	)		(2,443	)		(6,554	)
Discoveries		3			1			4			2,291			450			2,741			469			103			572
Extensions		512			100			612			30,032			11,976			42,008			5,752			2,095			7,847
Technical Revisions		700			(53	)		647			(15,560	)		(15,893	)		(31,453	)		6,812			(7,189	)		(377	)
Economic Factors		216			106			322			17,405			7,049			24,454			8,243			2,820			11,063
Improved Recovery		49			17			66			32,974			6,798			39,772			12,243			107			12,350
Production		(1,297	)		-			(1,297	)		(78,737	)		-			(78,737	)		(22,406	)		-			(22,406	)
December 31, 2005		9,107			2,470			11,577			766,200			252,478			1,018,678			241,957			106,798			348,755

UNITED STATES	Light and Medium Crude Oil								Heavy Oil						Bitumen
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, 2004		-			-		-			-		-		-		-		-		-
Acquisitions		20,076			4,235		24,311			-		-		-		-		-		-
Divestments		-			-		-			-		-		-		-		-		-
Discoveries		-			-		-			-		-		-		-		-		-
Extensions		-			-		-			-		-		-		-		-		-
Technical Revisions		624			438		1,062			-		-		-		-		-		-
Economic Factors		-			-		-			-		-		-		-		-		-
Improved Recovery		-			-		-			-		-		-		-		-		-
Production		(885	)		-		(885	)		-		-		-		-		-		-
December 31, 2005		19,815			4,673		24,488			-		-		-		-		-		-

(continues on next page)

UNITED STATES (continued)	Natural Gas Liquids						Associated and Non-Associated Gas (Natural Gas)								Total
Factors	Proved		Probable		Proved Plus Probable		Proved			Probable		Proved Plus Probable			Proved			Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)			(MMcf)		(MMcf)			(MBOE)			(MBOE)		(MBOE)
December 31, 2004		-		-		-		-			-		-			-			-		-
Acquisitions		-		-		-		10,738			27,535		38,273			21,866			8,824		30,690
Divestments		-		-		-		-			-		-			-			-		-
Discoveries		-		-		-		-			-		-			-			-		-
Extension		-		-		-		-			-		-			-			-		-
Technical Revisions		-		-		-		792			120		912			756			458		1,214
Economic Factors		-		-		-		-			-		-			-			-		-
Improved Recovery		-		-		-		-			-		-			-			-		-
Production		-		-		-		(486	)		-		(486	)		(966	)		-		(966	)
December 31, 2005		-		-		-		11,044			27,655		38,699			21,656			9,282		30,938

TOTAL ENERPLUS	Light and Medium Crude Oil									Heavy Oil									Bitumen
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, 2004		66,272			14,892			81,164			26,971			8,264			35,235			-		43,640			43,640
Acquisitions		21,425			5,132			26,557			-			-			-			-		-			-
Divestments		(1,099	)		(778	)		(1,877	)		(1,205	)		(702	)		(1,907	)		-		-			-
Discoveries		84			27			111			-			-			-			-		-			-
Extensions		202			(21	)		181			33			20			53			-		-			-
Technical Revisions		(1,165	)		(1,118	)		(2,283	)		1,136			(441	)		695			9,358		(2,490	)		6,868
Economic Factors		3,814			1,190			5,004			1,312			349			1,661			-		-			-
Improved Recovery		2,939			316			3,255			3,759			(1,359	)		2,400			-		-			-
Production		(6,230	)		-			(6,230	)		(2,641	)		-			(2,641	)		-		-			-
December 31, 2005		86,242			19,640			105,882			29,365			6,131			35,496			9,358		41,150			50,508

TOTAL ENERPLUS (continued)	Natural Gas Liquids									Associated and Non-Associated Gas (Natural Gas)									Total
Factors	Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable			Proved			Probable			Proved Plus Probable
	(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(MMcf)			(MBOE)			(MBOE)			(MBOE)
December 31, 2004		8,942			2,318			11,260			778,610			243,208			1,021,818			231,953			109,649			341,602
Acquisitions		31			10			41			20,469			32,028			52,497			24,868			10,480			35,348
Divestments		(49	)		(29	)		(78	)		(10,546	)		(5,603	)		(16,149	)		(4,111	)		(2,443	)		(6,554	)
Discoveries		3			1			4			2,291			450			2,741			469			103			572
Extensions		512			100			612			30,032			11,976			42,008			5,752			2,095			7,847
Technical Revisions		700			(53	)		647			(14,768	)		(15,773	)		(30,541	)		7,568			(6,731	)		837
Economic Factors		216			106			322			17,405			7,049			24,454			8,243			2,820			11,063
Improved Recovery		49			17			66			32,974			6,798			39,772			12,243			107			12,350
Production		(1,297	)		-			(1,297	)		(79,223	)		-			(79,223	)		(23,372	)		-			(23,372	)
December 31, 2005		9,107			2,470			11,577			777,244			280,133			1,057,377			263,613			116,080			379,693

Reconciliation of Changes in Net Present Value of Future Net Revenue

The following table sets forth a reconciliation of changes in the net present value of future net revenues associated with Enerplus' net Proved Reserves, by country and in total, from December 31, 2004 to December 31, 2005 using constant prices and costs and discounted at 10% per year.

Canada

	(in $ millions)
Period and Factor
Estimated Future Net Revenue at December 31, 2004		2,933.8
Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties		(950.0	)
Net Change in Prices, Production Costs and Royalties Related to Future Production		2,169.8
Changes in Previously Estimated Development Costs Incurred During the Period		113.3
Changes in Estimated Future Development Costs		(229.0	)
Net Change Resulting from Extensions and Improved Recovery		412.7
Net Change Resulting from Discoveries		10.7
Changes from Acquisitions of Reserves		39.8
Changes from Dispositions of Reserves		(29.5	)
Net Change Resulting from Revisions in Quantity Estimates		126.1
Accretion of Discount		229.5
Net Change in Income Taxes		0.0
Estimated Future Net Revenue at December 31, 2005		4,827.2

United States

	(in $ millions)
Period and Factor
Estimated Future Net Revenue at December 31, 2004		0.0
Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties		(59.1	)
Net Change in Prices, Production Costs and Royalties Related to Future Production		0.0
Changes in Previously Estimated Development Costs Incurred During the Period		0.0
Changes in Estimated Future Development Costs		(78.8	)
Net Change Resulting from Extensions and Improved Recovery		0.0
Net Change Resulting from Discoveries		0.0
Changes from Acquisitions of Reserves		912.2
Changes from Dispositions of Reserves		0.0
Net Change Resulting from Revisions in Quantity Estimates		0.0
Accretion of Discount		0.0
Net Change in Income Taxes		(195.7	)
Estimated Future Net Revenue at December 31, 2005		578.6

(continues on next page)

Total Enerplus

	(in $ millions)
Period and Factor
Estimated Future Net Revenue at December 31, 2004		2,933.8
Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties		(1,009.1	)
Net Change in Prices, Production Costs and Royalties Related to Future Production		2,169.8
Changes in Previously Estimated Development Costs Incurred During the Period		113.3
Changes in Estimated Future Development Costs		(307.8	)
Net Change Resulting from Extensions and Improved Recovery		412.7
Net Change Resulting from Discoveries		10.7
Changes from Acquisitions of Reserves		952.0
Changes from Dispositions of Reserves		(29.5	)
Net Change Resulting from Revisions in Quantity Estimates		126.1
Accretion of Discount		229.5
Net Change in Income Taxes		(195.7	)
Estimated Future Net Revenue at December 31, 2005		5,405.8

Undeveloped Reserves

The following table discloses the volumes of Undeveloped Reserves of Enerplus that were first attributed in the years indicated.

Proved Undeveloped Reserves

	Crude Oil
Year	Heavy		Light and Medium		Bitumen		NGLs		Natural Gas		Total
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Bcf)		(MBOE)
2003		950		320		-		35		27.5		5,888
2004		189		1,182		-		55		63.0		11,920
2005		768		2,524		-		414		55.0		12,873

Probable Undeveloped Reserves

	Crude Oil
Year	Heavy		Light and Medium		Bitumen		NGLs		Natural Gas		Total
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Bcf)		(MBOE)
2003		74		263		-		80		33.9		6,067
2004		950		1,808		47,747		40		25.0		54,711
2005		126		902		-		104		22.0		4,799

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 the estimates of future capital expenditures, Enerplus expects this to continue.

Proved and Probable Reserves Not on Production

Enerplus has approximately 5,912.8 MBOE of Proved plus Probable Reserves which are capable of production but which, as of December 31, 2005, were not on production. These reserves do not include the Probable Reserves attributable to Enerplus' interest in the SAGD-recoverable bitumen reserves in the Joslyn Project. These reserves have generally been non-producing for periods ranging from a few months to more than five years. In general, these reserves are related to commercially producible volumes that are not producing due to production requirements of other reserve formations or zones in the same well bore, or are related to reserves volumes which require the completion of infrastructure before production can begin.

OPERATIONAL INFORMATION

Overview

Enerplus' operational strategies and activities are directed towards maximizing value and distributable income over the long-term. Enerplus utilizes its technical and operating experience to increase value through acquisitions and through development and optimization activities on new and existing oil and natural gas properties. Enerplus achieves this value creation through a focused and disciplined acquisition strategy, an active capital development program directed towards lower risk development and optimization of its existing assets.

Enerplus' acquisition strategy is generally directed towards longer-life assets with lower risk development potential which fit within core strategic areas and complement the existing asset base. Enerplus typically funds its acquisitions by drawing from its existing credit facility, the issuance of Trust Units or a combination of both.

Enerplus develops its properties through lower risk development projects which include infill drilling, step-out drilling, joint venture arrangements, farmouts, waterflood implementation and other activities. Enerplus' development investments currently focus on waterfloods, shallow natural gas, coalbed methane and bitumen in Western Canada and Bakken oil development in Montana and North Dakota. Enerplus also invests in development of other conventional oil and gas properties in Canada. On higher risk opportunities, Enerplus generally enters into farmout arrangements under which an exploration-oriented company would pursue the opportunities on Enerplus' behalf, generally at no cost to Enerplus, in exchange for a portion of Enerplus' interests. Enerplus may pursue some higher risk opportunities on its own if the risk/return ratio justifies the risk. Enerplus typically looks for projects of sufficient size which, if proven, could materially add to the value of the Fund going forward.

Optimization of Enerplus' existing assets takes the form of downhole recompletions and stimulations, enhancement of artificial lift, water injection and facility optimization and other activities. These activities are typically smaller projects with attractive rates of return given the limited capital investment required and rapid payback.

Risk management is a key strategy for Enerplus. This is achieved through an acquisition focus which is generally concentrated on longer-life properties which typically have more predictable production and reserves, lower risk development activities and partnering on higher risk activities through joint venture or farmout arrangements, and other risk mitigation actions. Enerplus has historically experienced an approximate 99% drilling success rate by avoiding a large component of exploration type drilling which is typically higher risk.

Description of Principal Properties and Operations

Outlined below is a description of Enerplus' oil and natural gas operations and each of Enerplus' main types of operational activities, or "play types". All production information represents Enerplus' "company interest" in production from these properties, which includes overriding royalty interests of Enerplus but is calculated before deduction of royalty interests owned by others. All references to reserve volumes represent Enerplus' estimated "company interest" reserves (before deduction of royalties) contained in the Sproule Report, GLJ Report or D&M Report, as applicable, using forecast prices and costs. See "Presentation of Enerplus' Oil and Gas Reserves and Production Information".

Enerplus' oil and natural gas property interests are located in western Canada in the provinces of British Columbia, Alberta, Saskatchewan and Manitoba and in the United States in the states of Montana and North Dakota. All of Enerplus' major properties have related field production facilities and infrastructure to accommodate Enerplus' production. Production volumes for the year ended December 31, 2005 from Enerplus' properties consisted of approximately 43% crude oil and NGLs and 57% natural gas on a BOE basis. Enerplus' 2005 production was comprised of average daily production of 29,315 bbls/d of crude oil, 4,689 bbls/d of NGLs and 274.3 MMcf/d of natural gas for a total of 79,727 BOE/d, an increase of 6% when compared to the previous year. As of the date of this Annual Information Form, approximately 65% of this production is operated by Enerplus and the remaining 35% is operated by industry partners. As at December 31, 2005, the oil and natural gas property interests held by Enerplus were estimated to contain Proved plus Probable Reserves of 177.9 MMbbls of crude oil and NGLs, 53.2 MMbbls of Bitumen and 1,308.3 Bcf of natural gas for a total of 449.1 MMBOE. See "Oil and Natural Gas Reserves".

Enerplus' acquisition and development activities are focused on resource plays that are typically large and extensive accumulations of discovered oil and natural gas with limited geological risk. Resource plays typically cover large geographic areas and require many wells to develop the play over time. With a large number of wells generating a relatively predictable "average" or "type well", the timing, cost, production rates and reserve additions associated with the play can be more accurately predicted. Production from Enerplus' resource plays generally exhibit low declines over the long term, with long reserve life. Enerplus' resource plays include shallow natural gas in southeast Alberta and southwest Saskatchewan, coalbed methane in central Alberta, oil sands in northeast Alberta and Bakken oil in Montana. In addition, Enerplus owns interests in 12 major and 15 minor waterflood properties throughout western Canada. Waterfloods are similar to resource plays in that the oil in place is a relatively known quantity, production declines are relatively low and the goal is to maximize recovery of a known resource. Other conventional oil and gas properties make up the balance of the Enerplus portfolio. Outlined below is a more detailed description of each of Enerplus' play type.

Shallow Natural Gas

Shallow natural gas has been a core development area for Enerplus since the late 1990s. The shallow natural gas formations in southeast Alberta and southwest Saskatchewan cover an area of over 10,000 square kilometres. These zones are typically less than 800 metres in depth with most production coming from the Milk River, Medicine Hat, and Second White Specks producing zones. Shallow natural gas is Enerplus' second largest resource play by production as it represented approximately 17% of Enerplus' 2005 average daily production and approximately 20% of its Proved plus Probable reserves (representing approximately 90 MMBOE). Enerplus participated in drilling 336 gross (200.5 net) shallow natural gas wells in 2005. Total capital expenditures for shallow natural gas operations were $58.7 million in 2005.

Production from Enerplus' shallow natural gas operations for the year ended December 31, 2005 averaged approximately 82.6 MMcf/d of natural gas. The largest shallow natural gas producing properties are Bantry, Hanna Garden Plains, Verger, Countess, and Medicine Hat South in Alberta and Shackleton in Saskatchewan, all of which have associated pipeline infrastructure and compression facilities. Enerplus is the operator of most of the production from these areas, except for Shackleton which is operated by a third party.

Enerplus plans to invest approximately $74 million on shallow natural gas development in 2006, including drilling approximately 570 gross (300 net) wells, including 121 gross (108 net) high density wells within existing producing areas. The largest parts of the 2006 development program will be at Shackleton, Atlee Buffalo, Bantry, Medicine Hat North, Hanna Garden, and Verger.

Waterfloods

Waterflood development is Enerplus' largest play type. In a waterflood play, water is injected into the producing reserves formation to supplement the original reservoir pressure and provide a drive mechanism to move additional oil to the producing well. Pressure maintenance and the production of oil from water injection can result in a production profile with decreasing and stable declines and higher recovery of reserves. Infill drilling and well/injector optimization are effective methods of enhancing reserve recovery even further. Enerplus' waterflood plays produced approximately 18,100 BOE/d in 2005, or approximately 23% of Enerplus' production during the year. At year-end 2005, Enerplus had waterflood oil and natural gas reserves of approximately 108 MMBOE, which represented approximately 24% of Enerplus' Proved plus Probable reserves. Enerplus invested approximately $62.2 million on waterflood development in 2005 including participation in drilling on 52 gross (36.7 net) development wells.

Enerplus' waterflood assets are found in Alberta, Saskatchewan, and Manitoba, the largest of which are Pembina 5 Way, Giltedge, Joarcam, the Medicine Hat Glauconitic "C" Unit, the Mitsue Unit, Virden, Silver Heights and Gleneath. Enerplus is the operator of these major areas, with the exception of Mitsue, which is non-operated. All of Enerplus' major waterflood areas have associated crude oil production installations for emulsion treating and injection or water disposal. In addition, Joarcam also has facilities for natural gas compression, dehydration and processing.

In 2005, Enerplus drilled 18 gross (17.5 net) Viking oil wells at the Joarcam property and completed construction of a crude oil battery to handle additional production. At Pembina 5 Way, Enerplus drilled 10 gross (10 net) Cardium oil wells and upgraded its battery and water injection capabilities. Development at the Medicine Hat Glauconitic "C" Unit included the drilling of 2 gross (1.6 net) horizontal infill oil wells along with facility and pump upgrades.

Enerplus plans to invest approximately $78 million on waterflood development activities in 2006, including participation in the drilling of approximately 80 gross (60 net) wells. Most of this drilling will occur at the Joarcam and Pembina areas.

Bakken Oil

Enerplus owns an approximate 70% average working interest in certain producing wells in the Sleeping Giant Bakken oil field in Richland County, Montana, which was acquired through the acquisitions of Lyco and Sleeping Giant LLC in 2005. Production from this area is from the Middle Bakken dolomite formation at a depth of approximately 10,000 feet and consists of sweet light oil and some natural gas. Since early 2000, the pool has been exploited with the drilling of horizontal wells coupled with hydraulic fracturing. Initial peak monthly average oil production rates on wells with 4,000 to 9,000 foot horizontal lateral wells has ranged between 300 and 400 bbls/d of crude oil and Enerplus expects to recover between 400 and 750 MBOE of oil and natural gas reserves over the life of each well. These wells cost approximately $3 million to $4 million each to drill, complete and tie-in. With a 2005 exit production rate of approximately 10,000 BOE/day, the Bakken play area accounted for approximately 12% of Enerplus' production at year-end of 2005. As of December 31, 2005, Enerplus had estimated Proved and Probable reserves of approximately 37 MMBOE in this play area.

Since the acquisitions of its property interests in 2005, Enerplus invested $29.1 million dollars in the Bakken play to drill 15 gross (9.4 net) wells. In 2006, Enerplus plans to further develop Sleeping Giant and expand the play on 120,000 net acres of undeveloped land in Montana and North Dakota. Enerplus plans to drill 43 gross (27 net) oil wells with the Bakken formation as the main target.

Oil Sands

The Joslyn Lease is located approximately 60 kilometres north of Fort McMurray in northern Alberta and contains oil sands rights in the McMurray formation. Enerplus became involved in the oil sands in 2002 through acquisition of a 16% working interest in the Joslyn Lease from Deer Creek Energy Ltd. Deer Creek is the operator of the Joslyn Project and intends to recover the bitumen located on the Joslyn Lease through a combination of multi-phased SAGD and mining development. In 2005, Deer Creek was acquired by Total S.A., a major international oil and gas company with experience in the extraction and refining of heavy oil.

In 2005, Enerplus invested approximately $33.2 million in the Joslyn Project, with $30.6 million directed to SAGD and $2.6 million directed to advancing the mine development. This capital was spent on, among other things, drilling 271 gross delineation wells, beginning construction of a 62 kilometre, 40,000 bbls/d sales pipeline, and the purchase of 4.5 gross sections of land adjacent to the existing Joslyn Lease acreage. Enerplus and Deer Creek, in cooperation with industry participants, also initiated a pilot project to explore the potential of burning emulsified bitumen as an alternative fuel to natural gas, and continued to develop the 10,000 bbls/d SAGD Phase II project on schedule. The SAGD Phase I facility and well pair are currently producing 200 bbls/d, and are providing useful information for the operation of SAGD Phase II.

In a transaction subsequent to the year end, Enerplus sold a 1% working interest in the Joslyn Project in exchange for equity in Laricina Energy Ltd. ("Laricina"), a new private oil sands focused company led by the former Chief Executive Officer of Deer Creek. Included in the sale is an area of mutual interest agreement which has been designed to jointly pursue additional in-situ oil sand ventures. Following the sale to Laricina, Enerplus now has a 15% working interest in the Joslyn Project.

Enerplus will continue to develop the Joslyn Project with Deer Creek in 2006 and expects to invest $31 million in the Joslyn Project in 2006, including $6 million to further pursue the mine development by drilling additional core holes, receiving regulatory approvals, and engineering and design work. SAGD Phase II drilling and the construction of the water treatment and central facilities is also anticipated to be completed in 2006. Enerplus also expects that the 2006 investment will lead to receiving regulatory approval for both the 15,000 bbls/d SAGD Phase III A and the first stage of the mine. The reserves attributed to Enerplus' interest in the Joslyn Project as described under "Oil and Natural Gas Reserves -- Summary of Joslyn Project Bitumen Reserves" only include reserves attributable to SAGD Phases I, II, and III A of the Joslyn Project and do not include any reserves attributable to SAGD Phase III B or the mine portion of the Joslyn Project.

The current plans of Deer Creek, as provided to Enerplus, for the Joslyn Project are as follows:

Sanctioned Projects	Joslyn Project Production/ Throughput		Net Production/ Throughput⁽¹⁾		Net Future Development Capital⁽¹⁾		Start Up⁽²⁾		Full Production/ Throughput
	(bbls/d)		(bbls/d)		($millions)
SAGD Phase I (Pilot)		200		30				Q2 2004		2005
SAGD Phase II		10,000		1,500		34		Q1 2006		2009

Future Development Projects
SAGD Phase IIIA and Phase IIIB		30,000		4,500		167		2008		2011
Mine Phase I		100,000		15,000		466		2010		2014
Mine Phase II		100,000		15,000		466		2016		2020
Upgrader		n/a		n/a		n/a		2013		2014

___________

Notes:

(1)	The net information presented in this table reflects Enerplus' 15% working interest after the sale of a 1% interest to Laricina in early 2006. GLJ's estimates of SAGD production may vary from Deer Creek's estimates of production described above.

(2)	Start-up for SAGD refers to initial steaming. Start up for mining refers to initial extraction.

Additionally, Enerplus has commissioned an interim engineering report by GLJ (the "GLJ Mine Report") to evaluate the reserves located in the northern portion of the Joslyn Lease (the "North Mine Project"). Enerplus anticipates the GLJ Mine Report will be completed in April 2006. Based on an application filed by Deer Creek with the Alberta Energy and Utilities Board and Alberta Environment in February 2006, Enerplus expects that the reserves associated with the North Mine Project may be reclassified from a resource to a probable reserve category, which would result in Enerplus including additional probable reserves (and the corresponding future development capital) associated with the Joslyn Project in its reserves reporting. The application filed by Deer Creek estimates 890 MMBOE of recoverable bitumen (133.5 MMBOE net to Enerplus) are contained in the proposed North Mine Project, and provides for two 50,000 BOE/d producing mine phases and approximately $2 billion of initial capital, plus additional future maintenance capital requirements. A determination of reserves and the value associated with those reserves, as determined in the GLJ Mine Report, cannot be made at this time. Deer Creek has also identified potential future mining bitumen resources associated with a southern mine which are not reflected in Enerplus' existing reserves and are not dealt with in the GLJ Mine Report or in Deer Creek's regulatory application. No assurance can be made as to the ultimate outcome of the Deer Creek application, the GLJ Mine Report or the future development of the North Mine Project or the southern mine.

Coal Bed Methane

Enerplus' coal bed methane ("CBM") commercial development has been focused on the Horseshoe Canyon formation in three areas in the central Alberta fairway. Horseshoe Canyon coals are typically dry and do not have the water handling issues often associated with CBM production. Production from CBM for the year ended December 31, 2005 averaged approximately 4.7 MMcf/d of natural gas. Enerplus' major CBM producing properties are Trochu, Bashaw, and Joffre, each of which is in central Alberta. All of Enerplus' major CBM producing areas have associated pipeline infrastructure and gas compression facilities. At December 31, 2005, Enerplus had estimated Proved plus Probable CBM reserves of approximately 32 Bcf (5.3 MMBOE).

Enerplus invested approximately $42 million on CBM development in 2005, including participation in the drilling of 130 gross (83.2 net) wells and associated pipeline infrastructure and natural gas compression facilities at Bashaw.

In 2006, Enerplus plans to invest approximately $49 million on CBM development, including participation in drilling of 150 gross (87 net) wells. The majority of this development will take place in the Horseshoe Canyon formation coals of Bashaw, Joffre, Trochu, and Gadsby. Enerplus also plans to invest in pilot projects for Mannville and other formation coals in 2006.

Other Conventional

In addition to the play types outlined above, Enerplus also owns other conventional oil and natural gas assets across western Canada. These assets include operated and non-operated properties and various reservoir and commodity types. Major conventional assets include the Deep Basin/Foothills natural gas properties in western Alberta and northeast British Columbia, the Bantry North oil property in southern Alberta and the oil properties located in southeast Saskatchewan. Average 2005 daily production from these other conventional properties was approximately 43,900 BOE/d or approximately 55% of Enerplus' production. These other conventional reserves accounted for approximately 34% of Enerplus' estimated total Proved plus Probable reserves as of December 31, 2005. Enerplus invested approximately $143.4 million on development activities in other conventional properties in 2005.

Major producing properties in the Deep Basin/Foothills category include (i) the sweet, liquids-rich natural gas plays in the Deep Basin region which encompasses the Elmworth, Karr, Wapiti, and South Wapiti producing fields, primarily operated by Burlington Resources Canada Ltd., Devon Canada Corporation and BP Canada Energy Company, (ii) interests in the deep sour natural gas play in the Hanlan, Alberta region operated by Petro-Canada, and (iii) interests in the Mount Benjamin natural gas property also operated by Petro-Canada. Major production facilities within this area include (i) a 3% interest in the Wapiti gas plant, (ii) an 8.5% interest in the Hanlan-Robb sour gas plant, (iii) a 2% interest in the Ram River sour gas plant, (iv) a 3% interest in the Burnt Timber sour gas plant, and (v) a 6% interest in the Elmworth gas plant. Enerplus invested approximately $28 million in Deep Basin/Foothills development in 2005 including participation in the drilling of 87 gross (6.2 net) wells. In December 2005, Enerplus' production from the Deep Basin/Foothills region was approximately 8,500 BOE/day.

Enerplus acquired a 100% working interest in the Bantry North oil property as part of the ChevronTexaco acquisition in mid-2004. Oil and natural gas production from this field is from the Sunburst formation and the reservoir is supported by natural water drive. In 2005, Enerplus invested approximately $25 million to drill 8 wells and installed facilities to handle existing and future incremental production. At the end of 2005, production was approximately 1,250 BOE/day. Enerplus expects additional production of approximately 1,400 BOE/day to come on stream during the first quarter of 2006 following the completion and start-up of a non-operated sour gas facility and meter station.

Operated conventional properties in southeast Saskatchewan include Tatagwa, Colgate, Heward and Neptune, as well as Routledge, Manitoba. Medium density oil production is generally pressure supported by natural water drive. In 2005, Enerplus invested $9.6 million to drill 8 gross (6.5 net) wells.

Other major facilities included in Enerplus' conventional oil and natural gas properties include (i) a 22% interest in the oil emulsion treating and water disposal facility at Hayter, Alberta; (ii) a 100% interest in the Pine Creek gas compression facility, (iii) an 11% interest in the Progress sour gas plant, (iv) a 14.7% interest in the Sylvan Lake gas plant, and (v) an 8% interest in the Minnehik Buck Lake sour gas plant.

Enerplus plans to invest approximately $164 million on development activities at other conventional properties in 2006. Major activities include drilling 80 gross (10 net) natural gas wells in the Deep Basin/Foothills areas at a cost of approximately $38 million, drilling 19 gross (13 net) oil wells in southeast Saskatchewan at a cost of approximately $22 million, and drilling 6 horizontal wells and upgrading existing pumps at Bantry North at a cost of approximately $10 million. Enerplus also plans to invest approximately $5 million to tie-in 2 gross (1 net) natural gas wells in the Shekelie area along with a 3-D seismic program to be conducted on Enerplus' lands.

Summary of Principal Production Locations

During the year ended December 31, 2005, on a BOE basis, 83% of Enerplus' production was derived from Alberta, 8% from Saskatchewan, 4% from Montana, 3% from British Columbia and 2% from Manitoba. The following table describes Enerplus' principal producing properties and the average daily production from those properties during the year ended December 31, 2005. All properties listed in the table (other than "Other") are located in Alberta unless otherwise noted.

2005 Average Daily Production

	Product
	Crude Oil
Property	Heavy (bbls/d)		Light and Medium (bbls/d)		NGLs (bbls/d)		Natural Gas (Mcf/d)		Total (BOE/d)
Sleeping Giant, Montana, U.S.A.⁽¹⁾		-		2,883		-		1,582		3,147
Bantry		2,556		-		52		26,500		7,025
Joarcam		-		2,073		109		6,108		3,200
Pembina 5 Way		-		2,251		145		2,119		2,749
Chinchaga		-		-		-		15,439		2,573
Hanna Garden		-		3		6		13,470		2,254
Pine Creek		-		7		546		10,034		2,225
Verger		-		2		-		13,038		2,175
Giltedge		2,047		-		-		148		2,072
Medicine Hat		1,609		-		-		950		1,767
Elmworth		-		-		513		7,370		1,741
Benjamin		-		-		11		9,657		1,621
Valhalla		-		342		100		6,729		1,564
Progress		-		575		81		5,039		1,496
Shackleton, Saskatchewan		-		-		-		8,809		1,468
Medicine Hat South		-		-		-		7,762		1,294
Mitsue		-		880		130		1,138		1,200
Shorncliff		1,074		-		11		284		1,132
Virden, Manitoba		-		1,129		-		-		1,129
Enchant⁽²⁾		-		317		24		2,360		734
Ferrier		-		54		251		4,747		1,096
Countess		-		-		1		6,412		1,070
Sylvan Lake		-		242		182		3,863		1,068
Hanlan		-		-		5		6,190		1,037
Hayter		991		-		1		54		1,001
Other		581		9,699		2,521		114,534		31,889
TOTAL		8,858		20,457		4,689		274,336		79,727

___________

Notes:

(1)

This property was acquired by Enerplus on August 30, 2005 and further interests were acquired on October 4, 2005. Production from this property is only included in Enerplus' operational results from such dates, and accordingly the annualized average daily production presented is not indicative of a full year of production results from this property.

(2)

Additional interests in this area were acquired by Enerplus on July 1, 2005. Production from this property is only included in Enerplus' operational results from such date, and accordingly the annualized average daily production presented is not indicative of a full year of production results from this property.

Oil and Natural Gas Wells and Unproved Properties

The following table summarizes, as at December 31, 2005, Enerplus' interests in producing wells and in non-producing wells which were not producing but which may be capable of production, along with Enerplus' interests in Unproved properties. Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the proportion of oil or natural gas production that constitutes the majority of production from that well.

	Producing Wells								Non-Producing Wells								Unproved Properties
	Oil				Natural Gas				Oil				Natural Gas				(thousand of acres)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta		3,342		1,281.8		5,532		2,819.0		776		301.0		532		219.1		695.5		300.9
Saskatchewan		1,596		403.7		685		392.0		173		30.9		30		10.7		154.2		72.3
British Columbia		201		23.4		117		24.1		42		5.0		69		17.2		122.5		54.5
Manitoba		557		309.6		-		-		16		9.9		-		-		13.8		10.2
Montana		107		64.4		-		-		2		1.0		-		-		73.9		47.5
North Dakota		1		1.0		-		-		-		-		-		-		118.1		70.8
Joslyn Project		15		2.4		-		-		-		-		-		-		29.7		4.8
Total		5,819		2,086.3		6,334		3,235.1		1,009		347.8		631		247.0		1,207.7		561.0

Enerplus expects its rights to explore, develop and exploit on approximately 112,000 net acres of Unproved Properties to ordinarily expire prior to December 31, 2006. Enerplus has no material work commitments on such properties and, where Enerplus determines appropriate, it can extend expiring leases by either making the necessary applications to extend or performing the necessary work.

Exploration and Development Activities

The primary operational focus of Enerplus is to pursue attractive risk/return growth opportunities through the development of existing properties and the acquisition of new properties. Enerplus will also continue its ongoing property rationalization program on a selective basis and any sale proceeds may be used to acquire interests in existing core areas or new properties with attractive exploitation opportunities.

During 2005, Enerplus participated in the drilling of 859 gross wells (393.3 net wells) with virtually a 100% net well success rate. The majority of Enerplus' drilling activity was in the shallow natural gas areas around Hanna Garden, Medicine Hat, Verger, Countess and Bantry. The Fund also had active operated drilling and facility programs in oil dominated areas such as Pembina, Joarcam, Giltedge and Medicine Hat Glauconitic "C". The Shackleton and Hatton shallow natural gas areas in southwestern Saskatchewan, the Deep Basin area of northwestern Alberta and the Foothills region of western Alberta were the focus areas of non-operated drilling activity in 2005. The following table summarizes the number and type of wells that Enerplus drilled or participated in the drilling of for the year ended December 31, 2005, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

	Canada								United States
	Development Wells				Exploratory Wells				Development Wells				Exploratory Wells
Category of Well	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Crude oil wells		140		56.9		4		4.0		14		8.9		1		0.5
Natural gas wells		634		308.8		38		8.6		-		-		-		-
Bitumen recovery wells		14		2.2		-		-		-		-		-		-
Service wells		13		3.4		-		-		-		-		-		-
Dry and abandoned wells		1		0.0		-		-		-		-		-		-
Total		802		371.3		42		12.6		14		8.9		1		0.5

Enerplus currently intends to focus its development activities in the Western Canadian Sedimentary Basin and on the Sleeping Giant property in Montana and North Dakota, although Enerplus also considers acquisitions outside of these areas. Enerplus' development activities are typically funded through debt which may be subsequently repaid through internally generated cash flow withheld by the Fund's Operating Subsidiaries, as well as through the issuance of Trust Units. Enerplus does not anticipate that the cost of funding these development activities will have a material effect on Enerplus' disclosed oil and gas reserves or future net revenue attributable to those reserves.

Quarterly Production History

The following table sets forth Enerplus' average daily production volumes, on a company interest basis, for each fiscal quarter in 2005 and for the entire year, separately for production in Canada and the United States and in total. Enerplus had no heavy crude oil or NGLs production in the United States in 2005.

	Year Ended December 31, 2005
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Canada
Crude oil
Light and medium oil (bbls/d)		18,288		17,352		17,196		17,469		17,574
Heavy oil (bbls/d)		9,160		8,741		8,958		8,580		8,858
Total crude oil (bbls/d)		27,448		26,093		26,154		26,049		26,432
Natural gas liquids (bbls/d)		4,621		4,549		4,538		5,045		4,689
Total liquids (bbls/d)		32,069		30,642		30,692		31,094		31,121
Natural gas (Mcf/d)		280,463		269,159		277,180		264,342		272,754
Total Canada (BOE/d)		78,813		75,502		76,889		75,151		76,580

United States
Light and medium crude oil (bbls/d)		N/A		N/A		2,321		9,118		2,883
Natural gas (Mcf/d)		N/A		N/A		1,176		5,102		1,582
Total United States (BOE/d)		N/A		N/A		2,517		9,968		3,147

Total Enerplus
Crude oil
Light and medium oil (bbls/d)		18,288		17,352		19,517		26,587		20,457
Heavy oil (bbls/d)		9,160		8,741		8,958		8,580		8,858
Total crude oil (bbls/d)		27,448		26,093		28,475		35,167		29,315
Natural gas liquids (bbls/d)		4,621		4,549		4,538		5,045		4,689
Total liquids (bbls/d)		32,069		30,642		33,013		40,212		34,004
Natural gas (Mcf/d)		280,463		269,159		278,356		269,443		274,336
Total Enerplus (BOE/d)		78,813		75,502		79,406		85,119		79,727

Quarterly Netback History

The following tables set forth Enerplus' average netbacks received for each fiscal quarter in 2005 and for the entire year (excluding the effects of commodity derivative instruments), separately for production in Canada and the United States. Enerplus had no heavy crude oil or NGLs production in the United States in 2005. Netbacks are calculated on the basis of prices received before the effects of commodity derivative instruments 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. As a result, no production costs are attributed to Enerplus' NGLs production or United States natural gas production as those costs have been attributed to the applicable wells' principal product type.

	Year Ended December 31, 2005
Light and Medium Crude Oil ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price⁽¹⁾	$	53.89		$	57.00		$	70.48		$	62.60		$	60.93
Royalties		(8.80	)		(9.18	)		(11.35	)		(9.83	)		(9.78	)
Production costs⁽²⁾		(12.03	)		(12.87	)		(14.12	)		(12.54	)		(12.88	)
Netback	$	33.06		$	34.95		$	45.01		$	40.23		$	38.27

United States
Sales price⁽¹⁾		N/A			N/A		$	74.96		$	66.55		$	68.25
Royalties⁽³⁾		N/A			N/A			(13.99	)		(13.01	)		(13.21	)
Production costs⁽²⁾		N/A			N/A			(1.96	)		(1.96	)		(1.96	)
Netback		N/A			N/A		$	59.01		$	51.58		$	53.08

Total Enerplus
Sales price⁽¹⁾	$	53.89		$	57.00		$	71.01		$	63.95		$	61.96
Royalties⁽³⁾		(8.80	)		(9.18	)		(11.66	)		(10.92	)		(10.26	)
Production costs⁽²⁾		(12.03	)		(12.87	)		(12.67	)		(8.91	)		(11.34	)
Netback	$	33.06		$	34.95		$	46.68		$	44.12		$	40.36

	Year Ended December 31, 2005
Heavy Oil ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada/Total Enerplus
Sales price⁽¹⁾	$	35.06		$	38.49		$	53.04		$	41.24		$	41.99
Royalties		(6.41	)		(7.02	)		(9.72	)		(7.59	)		(7.69	)
Production costs⁽²⁾		(8.30	)		(9.50	)		(9.48	)		(11.75	)		(9.73	)
Netback	$	20.35		$	21.97		$	33.84		$	21.90		$	24.57

	Year Ended December 31, 2005
Natural Gas Liquids ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada/Total Enerplus
Sales price⁽¹⁾	$	43.80		$	45.98		$	48.60		$	50.55		$	47.33
Royalties		(10.95	)		(11.03	)		(11.66	)		(12.14	)		(11.47	)
Production costs⁽²⁾		-			-			-			-			-
Netback	$	32.85		$	34.95		$	36.94		$	38.41		$	35.86

	Year Ended December 31, 2005
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Natural Gas ($ per Mcf)
Canada
Sales price⁽¹⁾	$	6.58		$	7.36		$	8.09		$	11.61		$	8.39
Royalties		(1.51	)		(1.63	)		(1.75	)		(2.14	)		(1.76	)
Production costs⁽²⁾		(0.90	)		(1.07	)		(1.00	)		(1.07	)		(1.01	)
Netback	$	4.17		$	4.66		$	5.34		$	8.40		$	5.62

United States
Sales price⁽¹⁾		N/A			N/A		$	8.24		$	13.58		$	12.58
Royalties⁽³⁾		N/A			N/A			(1.32	)		(2.17	)		(2.01	)
Production costs⁽²⁾		N/A			N/A			-			-			-
Netback		N/A			N/A		$	6.92		$	11.41		$	10.57

Total Enerplus
Sales price⁽¹⁾	$	6.58		$	7.36		$	8.09		$	11.65		$	8.41
Royalties⁽³⁾		(1.51	)		(1.63	)		(1.75	)		(2.15	)		(1.75	)
Production costs⁽²⁾		(0.90	)		(1.07	)		(1.00	)		(1.05	)		(1.01	)
Netback	$	4.17		$	4.66		$	5.34		$	8.45		$	5.65

	Year Ended December 31, 2005
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Total ($ per BOE)
Canada
Sales price⁽¹⁾	$	42.55		$	46.57		$	53.97		$	63.78		$	51.68
Royalties		(8.78	)		(9.39	)		(10.68	)		(11.51	)		(10.09	)
Production costs⁽²⁾		(6.98	)		(7.86	)		(7.88	)		(8.02	)		(7.68	)
Netback	$	26.79		$	29.32		$	35.41		$	44.25		$	33.91

United States
Sales price⁽¹⁾		N/A			N/A		$	72.98		$	67.82		$	68.86
Royalties⁽³⁾		N/A			N/A			(13.53	)		(13.01	)		(13.11	)
Production costs⁽²⁾		N/A			N/A			(1.80	)		(1.80	)		(1.80	)
Netback		N/A			N/A		$	57.65		$	53.01		$	53.95

Total Enerplus
Sales price⁽¹⁾	$	42.55		$	46.57		$	54.57		$	64.26		$	52.36
Royalties⁽³⁾		(8.78	)		(9.39	)		(10.77	)		(11.68	)		(10.21	)
Production costs⁽²⁾		(6.98	)		(7.86	)		(7.69	)		(7.29	)		(7.45	)
Netback	$	26.79		$	29.32		$	36.11		$	45.29		$	34.70

___________

Notes:

(1)	Net of transportation costs but before the effects of commodity derivative instruments.

(2)

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

(3)	Includes U.S. state production taxes.

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, industry information sources and a cost formula used by the Alberta Energy Utilities Board, 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 $422 million on an undiscounted basis and $54 million discounted at 10%. The calculations of future net revenue under "Oil and Natural Gas Reserves" above have excluded approximately $232 million on an undiscounted basis and $27 million discounted at 10% as these calculations do not reflect any costs for abandonment and reclamation for facilities and wells for which no reserves have been attributed. In the next three financial years, Enerplus anticipates that a total of approximately $22.5 million on an undiscounted basis and $19.1 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

Tax Horizon

Canadian

No cash Canadian income taxes have been paid by the Fund or its Canadian Operating Subsidiaries for the year ended December 31, 2005. Under Enerplus' current structure, taxable income of the Canadian Operating Subsidiaries is transferred through interest, royalty and other distribution payments to the Fund, which in turn, allocates all of its taxable income to the unitholders. Therefore, no Canadian income taxes are currently expected to be incurred by the Fund or its Canadian Operating Subsidiaries in the future.

United States

A total of $2.8 million of U.S. income related cash taxes were incurred with respect to U.S. operations in the year ended December 31, 2005. Enerplus' U.S. operations are subject to income taxes payable on the taxable income determined under U.S. income tax rules and regulations. As funds are repatriated back to Canada, withholding taxes as required by U.S. tax law would become payable. As a result, Enerplus' U.S. operations are expected to continue to incur U.S. income related cash taxes in the future.

For additional information, see Notes 1(h) and 11 to the Fund's audited financial statements for the year ended December 31, 2005.

Costs Incurred

In the financial year ended December 31, 2005, Enerplus made the following expenditures:

	Property Acquisition Costs
	Proved		Unproved		Exploration Costs		Development Costs
	($ in millions)
Canada	$	91.5	$	10.6	$	9.9	$	319.1
United States		589.6		22.9		1.8		27.3
Total	$	681.1	$	33.5	$	11.7	$	346.4

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 (net of transportation costs but before the effects of commodity derivative instruments) of $61.96/bbl for its light and medium crude oil, $41.99/bbl for its heavy crude oil and $47.33/bbl for its NGLs for the year ended December 31, 2005, compared to $47.87/bbl for its light and medium crude oil, $34.98/bbl for its heavy crude oil and $38.14/bbl for its NGLs for the year ended December 31, 2004. Enerplus

has a long term transportation commitment to deliver 2,480 bbls/d of Canadian production on the Plains Marketing Canada Joarcam Pipeline. Enerplus also has a long term gathering agreement for approximately 9,000 bbls/d of U.S. production on the Plains All American Trenton Pipeline System. Neither of these transportation agreements impact Enerplus' ability to market to a variety of purchasers under a variety of market-based terms.

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, managed and sold downstream under long term transportation and sales contracts to a variety of end users. These entire sales proceeds and transportation costs are pooled and paid equitably to all supply producers. In 2005, 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 consist of a total of 10 MMcf/d on each of the Foothills and Northern Border pipelines until October 31, 2008; 5 MMcf/d on the Alliance Pipeline until October 31, 2015; and 5 MMcf/d on each of the TransCanada and Viking Pipelines to Marshfield, Illinois 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 2005 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 55% compared to 58% in 2004. The average price received by Enerplus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2005 was $8.41/Mcf compared to $6.56/Mcf in the year ended December 31, 2004. Within its sales portfolio of aggregator, downstream and spot natural gas, Enerplus sold approximately 40% of its natural gas based on the AECO month index, 40% based on the AECO day index and 20% at NYMEX monthly index prices.

Future Commitments and Forward Contracts

Enerplus may use various types of financial instruments and fixed price physical sales contracts to manage the risk related to fluctuating commodity prices. Absent such hedging activities, all of the crude oil and NGLs and the majority of natural gas production of Enerplus is sold into the open market at prevailing spot prices, which exposes Enerplus to the risks associated with commodity price fluctuations and foreign exchange rates. See "Risk Factors". Information regarding Enerplus' financial and physical instruments is contained in Note 12 to the Fund's audited annual consolidated financial statements for the year ended December 31, 2005 and under the headings "Pricing" and "Price Risk Management" in the Fund's management's discussion and analysis for the year ended December 31, 2005, each of which is available through the Internet on Enerplus' SEDAR profile at www.sedar.com.

Environment, Health and Safety

Enerplus is committed to the ongoing health and safety of its employees, contractors and the general public as evidenced by its participation in industry recognized programs that drive and measure its Environment, Health and Safety ("EHS") performance. Enerplus believes its efforts in EHS are essential to its continued corporate success and are important to all of its stakeholders. As a measure of its commitment to safety, Enerplus received industry recognition from Work Safe Alberta with a "Best Safety Performer" award presented in 2005. Of Alberta's 128,000 employers, less than one percent received this award which is based upon stringent criteria of low lost time claims while maintaining strong compliance to regulatory requirements.

Enerplus has maintained its Certificate of Recognition ("COR") which is a framework developed by Alberta's Workplace Health and Safety to promote and utilize health and safety programs in the Province of Alberta. Enerplus first received this certificate in 2000 and has maintained its COR through annual reviews and a rigorous audit every three years, with the next audit due in 2006. Enerplus also continues to be an active Platinum Level participant (the highest level attainable) in the Environment, Health and Safety Stewardship

Program initiated by the Canadian Association of Petroleum Producers ("CAPP"). This stewardship program provides comparison on key benchmarks including recordable and lost time injuries for employees and contractors. Enerplus' employees outperformed industry peers as measured against CAPP's historical benchmark injury data with zero lost time incidents and only two minor medical aid incidents in 2005.

Continued focus on contractor safety through 2005 resulted in Enerplus outperforming CAPP's historical benchmark total recordable injury data in 2004 and maintained its four-year trend on total recordable injury frequency rate down to 1.53 per 200,000 man hours for 2005 in Canada. Contractor lost time frequency rates also trended downward from 0.73 per 200,000 man hours in 2004 to 0.46 per 200,000 man hours in 2005 in Canada. Contractor safety in the United States was not at as high a level as in Canada and will be a focus area for Enerplus in 2006. Contractor statistics for U.S. operations, which Enerplus added in August 2005 with the acquisition of Lyco, were 0.69 per 200,000 man hours and 1.66 per 200,000 man hours for lost time and total recordable injuries, respectively.

Enerplus remains committed to meeting its responsibilities to protect the environment wherever it operates through a variety of programs and actively monitor its compliance with all regulators. Key efforts include:

(i)

utilizing employee awareness training and facility inspections to improve its overall environmental awareness, reduce flared and vented volumes and mitigate the impact from environmental incidents at its operated facilities;

(ii)

monitoring and tracking emissions at its facilities is part of its on-going commitment to meet various reporting initiatives including the National Pollutant Release Inventory and the CAPP Benzene Emissions and Green House Gas Emissions benchmarks;

(iii)

maintaining an active well abandonment and site restoration program. Enerplus continued to assess and remediate sites impacted by historic operations, with a primary focus on spill sites, flare pit and drill sump removal. Enerplus also maintained comprehensive inspection programs and initiated facility upgrades in 2005 targeted at improving the integrity of surface pipe, storage tanks and underground pipelines; and

(iv)

initiating a review of all of its pipelines that cross bodies of water in order to identify high risk crossings and implement appropriate emergency response plans. In 2005, an area study was reviewed with the findings of this study being used to define the longer term, company wide program that will be implemented in 2006. Enerplus' emergency response plans are continuously reviewed to ensure protection of the environment from accidental spills or releases. Operators are trained in emergency response for both safety and environmental incidents to mitigate the impacts of unexpected releases.

Increased emphasis on non-saline water use, particularly in sensitive water shed areas, is a focus in 2006. To that end, Enerplus has implemented a study to review and minimize this water use and ensure protection of non-saline water sites while at the same time ensuring that it has sufficient water to maintain its operations.

Overall, Enerplus spent $7.8 million on EHS related activities, which is higher than its historical spending in this area. In 2006, Enerplus plans to spend $10.4 million toward EHS initiatives as part of its ongoing commitment.

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 2% of the total development expenditures incurred by Enerplus in 2005. See "Industry Conditions - Environmental Regulation" and "Risk Factors".

Additional Operational Information

Insurance

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

Personnel

As at December 31, 2005, Enerplus employed a total of 566 persons.

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., 66²/₃% 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 amounts 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 66²/₃% of the votes cast at a meeting of unitholders called for that purpose. The Trustee or any successor may resign upon 60 days notice to EnerMark. Such resignation or removal shall become effective upon the acceptance of appointment by a successor trustee. If the Trustee is removed by EnerMark, EnerMark may appoint a successor trustee. If the Trustee resigns or is removed by unitholders, its successor must be either appointed by EnerMark or the unitholders. If a successor trustee does not accept its appointment as trustee, a court may appoint the successor trustee.

The Trust Indenture provides that the Trustee shall exercise the powers and discharge the duties of its office honestly, in good faith and in the best interests of the Fund and its unitholders and shall exercise the degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. 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.

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 66²/₃% 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

As long as the fund is able to meet the "TCP Exception" described under "Risk Factors - Risks Related to Enerplus' Structure and Ownership of the Trust Units - Changes in tax and other laws may adversely affect unitholders", there is no specified limitation in the Tax Act as to the level of non-Canadian resident ownership of the Trust Units. However, absent the TCP Exception, in order for the Fund to maintain its status as a mutual fund trust under the Tax Act, it may be necessary for the Fund to ensure that it has not been established or maintained primarily for the benefit of non-residents of Canada ("non-residents") within the meaning of the Tax Act or to otherwise restrict the number of Trust Units held by non-residents. Accordingly, the Trust Indenture provides that, from time to time, EnerMark may restrict the number of Trust Units owned by non-residents and take all necessary steps to monitor the ownership of the Trust Units such that the Fund maintains the status of a unit trust and mutual fund trust for the purposes of the Tax Act. The Trust Indenture also provides that, if at any time EnerMark becomes aware that the number of Trust Units owned by non-residents exceeds the restricted number of Trust Units as determined by EnerMark, or that such a situation is imminent, EnerMark, on behalf of the Fund, will make a public announcement of the situation and will take steps to ensure no additional Trust Units are issued or transferred to non-residents, and may require non-residents (generally chosen in the inverse order of acquisition or registration of the Trust Units) to sell their Trust Units, or a portion thereof, in order to reduce the level of non-resident ownership below the determined threshold. The Fund's transfer agent may require declarations as to residency to effect these provisions.

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

For additional information regarding non-resident ownership restrictions and developments, see "Risk Factors - Risks Related to Enerplus' Structure and Ownership of the Trust Units".

Investments of the Fund

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

Distributions of Distributable Income

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

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

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

Meetings of Unitholders and Voting

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

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

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

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

Redemption Right

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

(i)

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

(ii)

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

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

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

Repurchase of Trust Units

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

Term and Termination of the Fund

The Trustee shall commence to wind up the affairs of the Fund when there are no longer any Trust Units outstanding. However, the Fund may be terminated earlier if the unitholders vote by extraordinary resolution (meaning 66²/₃% 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.

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 66²/₃% 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:

(i)

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

(ii)

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;

(iii)

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

(iv)

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;

(v)

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;

(vi)

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

(vii)

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 Notes

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

Royalty Agreements

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

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

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

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

Unsecured, Subordinated Promissory Notes of EnerMark

EnerMark has issued unsecured, subordinated promissory notes to the Fund. The subordinated notes bear interest at various annual rates, expire at various dates and the principal amounts of the notes vary as additional funds (generally from the issuance of Trust Units) are loaned from the Fund to EnerMark and principal repayments are made on the notes. The payment of principal and interest on the notes is subordinated to the

prior payment in full of all other debt of EnerMark, other than debt which, by its terms or by operation of law, ranks equal with the subordinated notes. The Fund has entered into a subordination agreement pursuant to which the payment to the Fund by EnerMark of obligations under the subordinated notes issued to the Fund is subordinated and will rank junior to the indebtedness of EnerMark to its lenders and the holders of its senior unsecured notes.

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

As stated above, the terms of the existing royalty agreements and the subordinated debt issued by EnerMark to the Fund, together with the subordination agreements entered into by the Fund and the terms of EnerMark's credit facilities and senior notes, result in the royalty, interest, distribution and dividend payments from the Fund's Operating Subsidiaries to the Fund being subordinate to payments made, or required to be made, on indebtedness to third parties. As a result, royalty, interest, distribution and dividend payments from EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA to the Fund, and the related cash distributions from the Fund to unitholders, may be adversely affected if EnerMark is in default of such indebtedness or if there are variations in the terms of EnerMark's indebtedness to third parties, including interest rates or the timing or principal repayments. See "Risk Factors".

Management and Corporate Governance

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

Information regarding the Fund's corporate governance and the duties and procedures of the EnerMark board of directors and its committees is contained under the heading "Corporate Governance" in the Fund's 2005 Annual Report and under the heading "Statement of Corporate Governance Practices" in the Fund's information circular and proxy statement dated February 28, 2006. Enerplus fully complies with the provisions of National Instrument 58-101 - Disclosure of Corporate Governance Practices, Multilateral Instrument 52-109 - Certification of Disclosure in Issuer's Annual and Interim Filings and Multilateral Instrument 52-110 - Audit Committees adopted by the Canadian Securities Administrators and intends to fully comply with all other securities regulatory or stock exchange requirements relating to corporate governance. As mentioned above, all governance and management functions for Enerplus are contained within the Fund's wholly-owned Operating Subsidiary, EnerMark.

Unitholder Rights Plan

On March 5, 1999, the Fund entered into a Unitholder Rights Plan Agreement (the "Rights Plan") with CIBC Mellon Trust Company, as rights agent, which was approved by Enerplus' unitholders on April 23, 1999 and was renewed for an additional three years by the Enerplus unitholders at each of the 2002 and 2005 annual general and special meetings of unitholders. The Rights Plan generally provides that, following the acquisition by any person or entity of 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 acquiring person or entity, shall be entitled to acquire Trust Units at a discounted price. The Rights Plan is similar to other shareholder or unitholder rights plans adopted in the energy sector. A copy of the Rights Plan is available through the Internet on Enerplus' SEDAR profile at www.sedar.com, filed as a "Security holders document" on April 12, 2005.

DEBT OF ENERPLUS

The Fund may, with the approval of the board of directors of EnerMark, borrow, incur indebtedness, give any guarantee or enter into any subordination agreement on behalf of the Fund, or pledge or provide any security interest or encumbrance on any property of the Fund. At present, all indebtedness of Enerplus is incurred directly by its primary Operating Subsidiary, EnerMark. As at December 31, 2005, EnerMark had senior debt facilities comprised of an $850 million bank credit facility (the "Bank Credit Facility") and US$229 million of senior unsecured notes (the "Senior Unsecured Notes") (collectively, the "Credit Facilities"). The Credit Facilities are the legal obligation of EnerMark and are guaranteed by the Fund's other material subsidiaries. Payments on the Credit Facilities have priority over payments to the Fund and over claims of and future distributions to unitholders. In the event of a breach or a default, or a failure to refinance, distributions from the Fund to unitholders may be reduced or suspended. However, unitholders have no direct liability with respect to the Credit Facilities.

Bank Credit Facility

The $850 million Bank Credit Facility is an unsecured, covenant-based three year committed credit agreement with nine North American banks. As at December 31, 2005, $329 million was outstanding under this facility. This bank debt carries floating interest rates that Enerplus expects to range between 60.0 and 115.0 basis points over bankers' acceptance rates, depending on Enerplus' ratio of Consolidated Senior Debt to Consolidated EBITDA (each as defined below).

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

•

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

•

the ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA at the end of any fiscal quarter shall not exceed 4:1; and

•

the ratio of Consolidated Senior Debt to Total Capitalization (as defined below) shall not exceed 50%, except that upon the completion of a Material Acquisition, and for a period extending to the end of the second full quarter thereafter, this limit increases to 55%.

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


Consolidated EBITDA:	The aggregate of the last four quarters' net income plus the sum of:

	• interest expense;
	• all provisions for federal, provincial or other income and capital taxes;
	• depletion, depreciation, amortization and accretion; and
	• other non-cash amounts.

Consolidated Senior Debt:	All indebtedness and obligations in respect of amounts borrowed excluding Subordinated Debt.

Consolidated Total Debt:	The aggregate of Consolidated Senior Debt and Subordinated Debt.

Material Acquisition:	An acquisition or series of acquisitions which increases the tangible assets of Enerplus by more than 5%.

Subordinated Debt:	Debt which, by its terms, is subordinated to the Bank Credit facility (but excludes convertible debentures which allow the Fund to issue Trust Units or other securities of the Fund in satisfaction of interest or principal).

Total Capitalization:	The aggregate of Consolidated Senior Debt and the Fund's unitholders' equity (calculated in accordance with GAAP as shown on the Fund's consolidated balance sheet).

Senior Unsecured Notes

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

Terms of Notes	US$175 million	US$54 million
Issued:	June 19, 2002	October 1, 2003

Maturity:	June 19, 2014	October 1, 2015

Coupon rate:	6.62%	5.46%

Semi-annual interest paid yearly on:	June 19 and December 19	April 1 and October 1

Principal payments in five annual equal instalments beginning:	June 19, 2010	October 1, 2011

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

•

the ratio of Consolidated EBITDA (as defined below) for the four immediately preceding fiscal quarters to consolidated interest expense shall be not less than 4.0 to 1.0;

•

Consolidated Debt (as defined below) is limited to 60% of the present value of Enerplus' Proved Reserves (discounted at 10% and based on forecast prices and costs); and

•

the ratio of Consolidated Debt to Consolidated EBITDA for each period of four consecutive fiscal quarters shall not exceed 3.0 to 1.0, but is permitted to be up to 3.5 to 1.0 for a maximum of six months.

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

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

Additional information regarding EnerMark's debt arrangements is contained in Note 8 to the Fund's audited annual consolidated financial statements for the year ended December 31, 2005 and under the heading "Liquidity and Capital Resources" in Enerplus' management's discussion and analysis for the year ended December 31, 2005. Notwithstanding that it is unsecured, the indebtedness of Enerplus to its lenders and senior noteholders ranks senior to and is in priority to the royalty, interest, distribution and dividend payments that are made to the Fund by its Operating Subsidiaries, and therefore ahead of distributions from the Fund to its unitholders. See "Information Respecting Enerplus Resources Fund - Description of the Royalty Agreements and Subordinated Notes" and "Risk Factors".

DISTRIBUTIONS TO UNITHOLDERS

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

Distributable Income

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

The amount of cash flow paid to the Fund from its Operating Subsidiaries, and the amount of cash distributions subsequently paid by the Fund to unitholders, depends on numerous factors including the Operating Subsidiaries' financial performance, debt covenants and obligations, working capital requirements and future capital requirements. Such amounts are, in part, subject to the discretion of the board of directors of EnerMark, which regularly evaluates the Fund's distribution payout with respect to anticipated cash flows, debt levels, capital expenditures plans and amounts to be retained to fund acquisitions and expenditures. In the past, the level of cash retained has typically varied between 10% and 40% of Enerplus' total annual cash flow. For the year ended December 31, 2005, approximately 36% of the cash available for distribution was retained.

The after-tax return from an investment in the Fund's Trust Units to unitholders subject to Canadian income tax can be made up of both a return on and a return of capital. That composition may change over time, thus affecting an investor's after-tax return. Returns on capital are generally taxed as ordinary income in the hands of a unitholder. Returns of capital are generally tax-deferred (and reduce the holder's cost base in the Trust Units for tax purposes).

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: (i) the sales price that Enerplus realizes for its oil and natural gas production (after hedging contract receipts and payments), (ii) the quantity of oil and natural gas that Enerplus produces, (iii) the cost to produce oil and natural gas and administer the Fund and its subsidiaries, (iv) the amount of cash retained for debt service or repayment or to fund capital expenditures, and (v) foreign currency exchange rates and interest rates. In addition, the level of distributions per Trust Unit will be affected by the number of outstanding Trust Units.

The following cash distributions have been paid or declared payable by Enerplus to its unitholders since the beginning of 2003:

Month of Record and Payment Date	2006		2005		2004		2003
January⁽¹⁾	$	0.42	$	0.35	$	0.35	$	0.30
February		0.42		0.35		0.35		0.32
March		0.42		0.35		0.35		0.35
April		N/A		0.35		0.35		0.35
May		N/A		0.35		0.35		0.37
June		N/A		0.35		0.35		0.37
July		N/A		0.35		0.35		0.37
August		N/A		0.37		0.35		0.37
September		N/A		0.37		0.35		0.37
October		N/A		0.37		0.35		0.37
November		N/A		0.42		0.35		0.35
December		N/A		0.42		0.35		0.35

___________

Note:

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

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

U.S. Tax Reporting Matters

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

Based upon the computation of current and accumulated earnings and profit in accordance with U.S. federal income tax principles, 93% of the distributions paid by the Fund during 2005 should be considered to be dividends. Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 (P.L. 108-27, 117 Stat. 752), the dividend portion of Enerplus' 2005 distributions should be considered "Qualified Dividends" eligible for the reduced rate of tax applicable to long term capital gains.

U.S. unitholders who received cash distributions were subject to at least a 15% Canadian withholding tax. The withholding tax is applied to both the taxable portion of the distribution as computed under Canadian tax law, and the non-taxable portion of the distribution. U.S. taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid.

INDUSTRY CONDITIONS

Overview

The oil and natural gas industry is subject to extensive controls and regulation governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government. The oil and natural gas industry is also subject to various agreements among the various federal, provincial and state governments with respect to pricing and taxation of oil and natural gas. Although it is not expected that any of these controls, regulations or agreements will affect Enerplus' operations in a manner materially different than they would affect other Canadian oil and gas issuers of similar size, the controls, regulations and agreements 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.

The discussion below focuses on the Canadian oil and natural gas industry (and particularly Alberta, where 83% of Enerplus' 2005 daily production occurred). In 2005, Enerplus acquired oil and natural gas properties and related assets in Montana and North Dakota in the United States. Enerplus' U.S. oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the federal government for operations on federal leases. These statutory provisions regulate matters such as the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements in order to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the abandonment of wells. Enerplus' U.S. operations are also subject to various conservation laws and regulations which regulate matters such as the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Additionally, the regulatory scheme as it relates to oil sands is somewhat different from that related to oil and gas generally. In Alberta, the regulation of oil sands operations, pipelines, upgraders and cogeneration facilities is undertaken jointly by the Alberta Energy and Utilities Board (the "EUB") pursuant to various statutes, including the Oil Sands Conservation Act (Alberta), and by Alberta Environment pursuant to Alberta's Environmental Protection and Enhancement Act. In addition to requiring certain approvals prior to the construction and operation of oil sands recovery projects, pipelines, upgraders and cogeneration facilities, the legislation allows the EUB to inspect and investigate and, where a practice employed or a facility used is hazardous to human health or the environment, to make remedial orders. Similar powers are available to the Alberta Environment. Certain changes to oil sands recovery operations, pipelines, upgraders and cogeneration facilities also require the approval of the EUB, the Alberta Environment, or both. The construction, operation, decommissioning and reclamation of facilities as part of a scheme to recover bitumen from oil sands, extract and upgrade products therefrom, and transport those products to market, may invoke regulation by the federal government under various federal statutes and regulations, including the Canadian Environmental Assessment Act, the Canadian Environmental Protection Act (Canada), the Fisheries Act (Canada) and the Navigable Waters Protection Act (Canada). Certain approvals or authorizations may be needed prior to construction, operation or modification of facilities or operational practices. Inspections and investigations may result in remedial orders.

Pricing and Marketing - Oil

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, as well as on the world price of oil. In Canada, oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, 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

The price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The 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 and, except as permitted in the enforcement of countervailing and anti-dumping orders and undertakings, minimum or maximum 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.

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. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases, and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands, respectively. 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.

The Province of Alberta imposes royalties of varying rates on the production of crude oil from lands in which it owns the mineral rights. 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 (applicable to oil pools discovered after March 31, 1974 and prior to October 1, 1992) and third tier oil (which is oil produced from pools discovered after September 30, 1992). The royalty rate on old oil is between 10% and 35%, for new oil it is between 10% and 30%, and for third tier oil it is between 10% and 25%.

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

Alberta's current royalty system for oil sands, introduced in 1997 and expiring June 30, 2007, is designed to support the development of the oil sands industry. An initial royalty of 1% of the quantity of oil sands product that is recovered and delivered to the royalty calculation point is payable until the owners have recovered specified allowed costs, including certain exploration and development costs, operating costs, a return allowance (based on the monthly federal long-term bond rate) and royalties paid to the Crown. Subsequent to such recovery, the royalty payable is the greater of the aforesaid 1% royalty and 25% of net revenue from an oil sands project. The foregoing royalty will approximate a 1% royalty on gross revenue before payout and a 25% royalty on net revenue after payout.

Land Tenure

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

Oil produced from oil sands owned by the Province of Alberta is produced under provincial Crown oil sands leases. While such leases may historically have had initial terms which varied in length, continuations beyond the initial terms are now subject to standardized criteria as provided for in the Oil Sands Tenure Regulation (Alberta). A lease may generally be continued after the initial term provided certain minimum levels of exploration or production have been achieved and all lease rentals (including escalating rentals) have been timely paid, subject to certain exceptions. The surface rights required for pipelines, upgraders and co-generation facilities are generally governed by leases, easements, rights-of-way, permits or licenses granted by landowners or governmental authorities.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well, pipeline and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. As well, applicable environmental laws may impose remediation obligations with respect to a property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage or the issuance of clean-up orders.

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

In 1994, the United Nations' Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which requires participating countries, upon ratification, to reduce their emissions of carbon dioxide and other greenhouse gases. Canada ratified the Kyoto Protocol in late 2002. The upstream Canadian oil and gas sector is in discussions with various federal and provincial levels of government regarding the development of green house gas regulations for the industry. Although the Canadian federal government has not released details of any implementation plan, it has stated that it intends to limit the emission reduction targets for the industry and regulate the cost of emission credits, which could result in increased capital expenditures and operating costs. However, until an implementation plan is developed, it is impossible to assess the impact on specific industries and any individual businesses within an industry. See "Risk Factors - Risks Related to Enerplus' Business and Operations - Enerplus' operation of oil and natural gas wells could subject it to environmental claims and liability".

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.

Worker Safety

Oilfield operations must be carried out in accordance with safe work procedures, rules and policies contained in provincial safety legislation. Such legislation requires that every employer ensures the health and safety of all persons at any of its work sites and all workers engaged in the work of that employer, and that every employer ensure that all of its employees are aware of their duties and responsibilities under the applicable legislation. Such legislation also provides for accident reporting procedures.

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:

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

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political conditions, including the risk of hostilities in the Middle East and global terrorism;

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currency fluctuations;

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global and domestic economic conditions;

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weather conditions;

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

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the production and storage levels of North American natural gas;

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the level of consumer demand;

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the price and availability of alternative fuels;

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

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the effect of world-wide energy conservation measures; and

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government regulations.

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

Enerplus may use 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.

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

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

The retention of cash flow in the Operating Subsidiaries of the Fund to finance capital expenditures or debt repayments may result in current income taxes being incurred by the Canadian Operating Subsidiaries and/or increased incomes taxes payable by the U.S. Operating Subsidiary. Payment of cash income taxes may in turn reduce the cash distribution made by the Fund to unitholders.

A return on an investment in the Fund is not comparable to the return on an investment in a fixed-income security. The recovery of an initial investment in the Fund is at risk, and the anticipated return on such investment is based on many performance assumptions. Although the Fund intends to make distributions of its available cash to unitholders of the Fund, these cash distributions may be reduced or suspended. Cash distributions are not guaranteed. The actual amount distributed will depend on numerous factors including: the financial performance of the Operating Subsidiaries of the Fund, debt obligations, commodity prices, production levels, working capital requirements, future capital requirements, applicable law and other factors beyond the control of the Fund. In addition, the market value of the Fund's Trust Units may decline if the Fund's cash distributions decline in the future, and that decline may be material.

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 sale in United States dollars. Currently, Enerplus does not engage in significant risk management activities related to foreign exchange rates, with the exception of the cross-currency swap associated with the US$175 million of senior unsecured notes issued by EnerMark in June 2002, as described in Note 8(b) to the Fund's audited consolidated financial statements for the year ended December 31, 2005.

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

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

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

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

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

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

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initial production rates;

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production decline rates;

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ultimate recovery of reserves;

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success of future exploitation activities;

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marketability of production;

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effects of government regulation; and

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

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

Estimates with respect to reserves that may be developed and produced in the future (particularly oil sands reserves) are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves.

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

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

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

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

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

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

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

The continuing production from a property, and to some extent the marketing of that production, is dependent upon the ability of the operators of Enerplus' properties. As of the date of this Annual Information Form, approximately 35% of Enerplus' daily production is from properties operated by third parties. To the extent a third-party operator fails to perform these duties properly or becomes insolvent, Enerplus' cash flow may be reduced. Third party operators also make estimates of future capital expenditures more difficult.

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

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

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

The payments of interest and principal with respect to Enerplus' indebtedness ranks ahead of payments of cash from Enerplus' Operating Subsidiaries to the Fund and therefore reduces amounts available for distribution from the Fund to unitholders. Enerplus has an unsecured credit facility available to it at variable interest rates. In addition, Enerplus has swapped US$175 million of its U.S. dollar denominated senior unsecured notes with fixed interest rates into Canadian dollar denominated floating rate debt. Variations in interest rates and scheduled principal repayments could result in significant changes to the amount of the cash flows required to be applied by the Operating Subsidiaries to their debt before payment of any amounts by them to the Fund. The agreements governing this credit facility and the senior unsecured notes each stipulate that if Enerplus is in default or fails to comply with certain covenants, the Fund's ability to make distributions to unitholders may be restricted. In addition, the Fund's right to receive payments from its Operating Subsidiaries is expressly subordinated to the rights of the lenders under the credit facility and the holders of the senior unsecured notes. See "Debt of Enerplus".

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

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

The Joslyn Project is in the early development stage and is subject to numerous risks.

The Joslyn Project is currently in the development stage. There is a risk that the Joslyn Project will not be completed on time or on budget or at all. Additionally, there is a risk that the Joslyn Project may have delays, interruption of operations or increased costs due to many factors, including, without limitation:

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breakdown or failure of equipment or processes;

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construction performance falling below expected levels of output or efficiency;

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design errors;

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contractor or operator errors;

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non-performance by third-party designers, contractors and suppliers or failure of third parties to construct the infrastructure required for the Joslyn Project to successfully proceed;

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labour disputes, disruptions or declines in productivity;

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increases in materials or labour costs;

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inability to attract sufficient numbers of qualified workers;

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delays in obtaining, or conditions imposed by, regulatory approvals;

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changes in Project scope;

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violation of permit requirements;

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disruption in the supply of energy;

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availability of drilling rigs and services;

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catastrophic events such as fires, earthquakes, storms or explosions; and

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challenges to the proprietary technology of Deer Creek and/or its affiliates.

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

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

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. See "Industry Conditions - Environmental Regulation".

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.

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

The oil and gas industry operates under federal, provincial, state and municipal legislation and regulation governing such matters as land tenure, prices, royalties, production rates, environmental protection controls, income, the exportation of crude oil, natural gas and other products, as well as other matters. The industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration and production rights, oil sands or other interests (including the terms and conditions relating to the Joslyn Lease and Joslyn Project), the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production), and possibly expropriation or cancellation of contract rights. See "Industry Conditions".

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

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

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

If Enerplus expands beyond its current areas of operations or expands the scope of operations beyond oil and natural gas production, 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 natural gas and coalbed methane production and development in the Western Canadian Sedimentary Basin and the northern United States, together with its participation in the development of oil sands reserves in the Joslyn Project. In the future, Enerplus may acquire oil and natural gas properties and assets outside this geographic area. In addition, the Trust Indenture does not limit Enerplus' activities to oil and natural gas production and development, and Enerplus could acquire other energy related assets, such as oil and natural gas processing plants or pipelines. Expansion of Enerplus' activities into new areas may present challenges and risks that it has not faced in the past, including dealing with additional regulatory matters. 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. Current high commodity prices coupled with a lack of qualified personnel in certain disciplines has created challenges for Enerplus in terms of recruiting and retaining key personnel. The loss of the services of key individuals could have a detrimental effect on the Fund. Investors should carefully consider whether they are willing to rely on the management of Enerplus before investing in the Trust Units.

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

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

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

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

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

From time to time, Enerplus conducts title reviews in accordance with industry practice prior to purchases of resource assets. However, if conducted, these reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat Enerplus' title to the purchased assets. If this type of defect were to occur, Enerplus' 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. Additionally, tax laws and tax treaties in foreign countries in which Enerplus operates or has financing structures may be changed or interpreted in a manner which is detrimental to Enerplus' operations and financial structure, and therefore the unitholders.

In particular, generally speaking, the Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must not be non-residents of Canada), unless at all times after February 21, 1990, "all or substantially all" of the trust's property consisted of property other than taxable Canadian property (the "TCP Exception"). Based on the most recent information obtained by Enerplus through its transfer agent and financial intermediaries, in February 2006 an estimated 73% of the Fund's issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act) at that time. The Fund is currently able to take advantage of the TCP Exception, and as a result, the Fund's Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents.

On March 23, 2004 the Canadian federal government announced proposed changes to the Tax Act which would have effectively eliminated, over a period of time, the TCP Exception currently relied on by Enerplus to maintain its mutual fund trust status, and would have required the Fund to comply with the requirement that it "not be maintained primarily for the benefit of non-residents" before January 1, 2007. In response to submissions from and discussions with stakeholders, the Canadian federal government suspended the implementation of those proposed amendments. The Canadian Minister of Finance indicated in the February 23, 2005 federal budget that further consultations would be pursued with stakeholders on taxation issues related to income trusts and other flow-through entities. On September 8, 2005, the Canadian Department of Finance released a discussion paper on these matters and invited interested parties to make submissions to the Department of Finance. On November 23, 2005, the former Canadian Minister of Finance issued a news release announcing that no change would be made to the tax treatment of income trusts in Canada and calling an end to the consultation process initiated in September 2005.

Notwithstanding the above, there is no assurance that the TCP Exception will continue to be available to the Fund or that the Canadian federal government will not introduce new changes or proposals to tax regulations directed at non-resident ownership which, given the Fund's level non-resident ownership, may result in the Fund losing its mutual fund trust status or could otherwise detrimentally affect Enerplus and the market price of the Trust Units. Enerplus intends to continue to take the necessary measures in order to ensure the Fund continues to qualify as a mutual fund trust under the Tax Act. For additional information regarding these matters, including the ability of Enerplus to adopt non-resident ownership constraints if required in order to ensure that the Fund maintains its mutual fund status and the consequences if the Fund lost its mutual fund trust status, see "Information Respecting Enerplus Resources Fund - Description of the Trust Units and the Trust Indenture - Non-Resident Ownership Provisions" and "Risk Factors - There would be material adverse consequences if the Fund lost its status as a mutual fund trust under Canadian tax laws".

See "General Development of Enerplus Resources Fund - Federal Government Pronouncements on Income Trusts and Mutual Fund Trust Status".

Enerplus may not be able to take steps necessary to ensure that the Fund maintains its mutual fund trust status. Even if the Fund is successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly "non-residents" of Canada (as defined in the Tax Act). The directors of Enerplus could impose a specific limit on the number of Trust Units that could be beneficially owned by non-residents of Canada, similar to the non-resident ownership restrictions in place for other income funds and royalty trusts in Canada, or could implement a dual-class unit structure what would effectively limit the aggregate number of Trust Units that could be owned by non-residents of Canada. Steps could be taken to ensure that no additional Trust Units are issued or transferred to non-residents, including limiting or suspending the trading of the Trust Units on the NYSE. If it is necessary to reduce the level of non-resident ownership below a certain level, non-residents may be required to sell all or a portion of their Trust Units. In these circumstances, the Trust Units would continue to trade on the TSX and non-residents of Canada would continue to be able to sell their Trust Units on that exchange. There can be no assurance that such circumstances would not detrimentally affect the market price of the Trust Units. See "Description of the Trust Units and the Trust Indenture - Non-Resident Ownership Provisions."

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

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

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

•

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

•

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

•

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

•

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

•

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

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

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

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

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

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

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

Notwithstanding the fact that Alberta (the Fund's governing jurisdiction) has adopted legislation purporting to limit trust unitholder liability, because of uncertainties in the law relating to investment trusts, there is a risk that a unitholder could be held personally liable for obligations of the Fund in respect of contracts or undertakings which the Fund enters into and for certain liabilities arising otherwise than out of contracts including claims in tort, claims for taxes and possibly certain other statutory liabilities. Enerplus has structured itself and attempted to conduct its business in a manner which mitigates the Fund's liability exposure and where possible, limit its liability to Fund property. However, such protective actions may not completely avoid unitholder liability. Notwithstanding Enerplus' attempts to limit unitholder liability, unitholders may not be protected from liabilities of the Fund to the same extent that a shareholder is protected from the liabilities of a corporation. Further, although the Fund has agreed to indemnify and hold harmless each unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a unitholder resulting from or arising out of the unitholder not having limited liability, Enerplus cannot assure prospective investors that any assets would be available in these circumstances to reimburse unitholders for any such liability. However, personal liability to unitholders of a trust in Canada is minimal where the beneficiaries are not controlling the day-to-day activities of the trust and there is no direct contact between the beneficiaries of the trust and parties who contract with the trust, each of which conditions is satisfied in the case of the Fund and its unitholders. Legislation that proposes to limit trust unitholder liability has been implemented in Alberta (which is the Fund's governing jurisdiction) but there is no assurance that such legislation will eliminate all risk of unitholder liability. Additionally, the Alberta legislation does not affect the liability of unitholders with respect to any act, default, obligation or liability that arose prior to July 1, 2004.

The redemption rights of unitholders is limited.

Unitholders have a limited right to require the Fund to repurchase Trust Units, which is referred to as a redemption right. See "Description of the Trust Units and the Trust Indenture - Redemption Right". It is anticipated that the redemption right will not be the primary mechanism for unitholders to liquidate their

investment. The Fund's ability to pay cash in connection with a redemption is subject to limitations. Any securities which may be distributed in specie to unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

Risks Particular to United States and Other Non-Resident Unitholders

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

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

The Fund may be a passive foreign investment company for United States federal income tax purposes for the 2005 taxable year and in subsequent taxable years. To date, Enerplus has received advice that the Fund should not be considered a passive foreign investment company for the years 2002, 2003 and 2004. If the Fund were classified as a passive foreign investment company, United States unitholders (other than most tax-exempt investors) would be subject to adverse tax rules. Under these adverse tax rules, United States unitholders generally would be required to allocate any gain or any excess distributions, which include any annual distributions other than in the first year the unitholder held Trust Units, that is greater than 125% of the average annual distributions received by that unitholder in the three preceding taxable years or, if shorter, that unitholder's holding period for Trust Units. The amount allocated to the current taxable year and any year prior to the first year in which Enerplus was a passive foreign investment company would be taxed as ordinary income in the current year. The amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each of the other taxable years. Holders will not be able to make a "qualified electing fund" election or, with respect to the Fund's Operating Subsidiaries that were considered to be passive foreign investment companies, a "mark-to-market" election to protect themselves from these potential adverse consequences if Enerplus were ultimately determined to be a passive foreign investment company. United States unitholders are strongly urged to consult their own tax advisors regarding the United States federal income tax consequences of Enerplus' possible classification as a passive foreign investment company and the consequences of such classification.

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

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

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

The Fund is a trust organized under the laws of Alberta, Canada, and Enerplus' principal place of business is in Canada. Most of the directors and all of the officers of Enerplus are residents of Canada and most of the experts who provide services to Enerplus (such as its auditors and some of its 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.

MARKET FOR SECURITIES

The Trust Units are listed and posted for trading on the TSX and 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 2005.

Month	High		Low		Close		Volume
January	$	48.00	$	41.90	$	47.12		2,980,951
February		49.16		44.25		46.27		4,730,319
March		48.79		40.00		43.88		4,297,787
April		46.60		41.55		44.40		4,477,469
May		45.56		40.55		44.31		4,738,048
June		47.50		44.20		46.80		3,624,328
July		49.00		46.40		48.90		4,644,770
August		50.97		44.82		49.85		8,410,988
September		55.14		48.50		54.91		5,941,908
October		56.50		45.79		49.70		7,846,506
November		54.28		47.91		53.50		5,514,764
December		58.55		53.50		55.86		5,070,256

The following table sets forth certain trading information for the Trust Units on the NYSE in 2005.

Month	High		Low		Close		Volume
January	US$	38.72	US$	34.20	US$	37.93		4,663,900
February		39.76		35.82		37.59		4,898,700
March		39.20		32.86		36.26		6,825,100
April		38.26		33.36		35.33		6,670,900
May		36.59		32.00		35.30		5,601,800
June		38.50		35.50		38.20		4,086,600
July		40.08		38.01		39.91		4,038,800
August		42.15		36.80		42.03		6,626,200
September		47.52		41.29		47.20		5,553,400
October		48.44		38.76		42.00		10,874,300
November		46.54		40.19		45.80		5,549,100
December		50.29		46.00		47.98		5,065,400

DIRECTORS AND OFFICERS

Directors of EnerMark

The directors of EnerMark are nominated by the unitholders of the Fund at each annual meeting of unitholders. All directors serve until the next annual meeting or until a successor is elected or appointed. The name, municipality of residence, year of appointment as a director of EnerMark and principal occupation for the past five years for each director of EnerMark are set forth below.

Name and Residence	Director Since	Principal Occupation for Past Five Years
Edwin Dodge^(3)(4)(6) Calgary, Alberta, Canada	May 2004	Corporate director since 2004. Prior thereto, Chief Operating Officer of Canadian Pacific Railway Limited ("CPR") (a public Canadian national rail company) since 2001. Prior thereto, various senior roles with CPR and its predecessors.

Gordon J. Kerr⁽¹⁰⁾ 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.

Douglas R. Martin⁽¹⁾⁽⁷⁾ Calgary, Alberta, Canada	July 2000	President of Charles Avenue Capital Corp. (a private merchant banking company).

Robert Normand^(2)(4)(8) Rosemere, Québec, Canada	June 2001	Corporate director.

Glen D. Roane⁽²⁾⁽⁴⁾ Canmore, Alberta, Canada	June 2004	Corporate director.

W.C. (Mike) Seth Calgary, Alberta, Canada	September 2005	President of Seth Consultants Ltd. (a private consulting firm) since March 1, 2006. Prior thereto, Chairman of McDaniel & Associates Consultants Ltd. ("McDaniel") (a petroleum engineering consulting firm) since July 2005. Prior thereto, President and Managing Director of McDaniel.

Donald T. West⁽⁵⁾⁽⁶⁾ Calgary, Alberta, Canada	April 2003	Businessman.

Harry B. Wheeler⁽²⁾⁽⁵⁾ Calgary, Alberta, Canada	January 2001	President of Colchester Investments Ltd. (a private investment firm).

Robert L. Zorich^(3)(6)(9) Houston, Texas, USA	January 2001	Managing Director of EnCap Investments L.P. (a private firm that provides private equity financing to the oil and gas industry).

___________

Notes:

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

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

(3)	The Corporate Governance and Nominating Committee is comprised of Robert L. Zorich as Chairman, Edwin Dodge and W.C. (Mike) Seth.

(4)	The Compensation and Human Resources Committee is comprised of Glen D. Roane as Chairman, Robert Normand and Edwin Dodge.

(5)	The Reserves Committee is comprised of Harry B. Wheeler as Chairman, W.C. (Mike) Seth and Donald T. West.

(6)	The Environment, Health and Safety Committee is comprised of Donald T. West as Chairman, Edwin Dodge and Robert L. Zorich.

(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)

Mr. Normand served as a director of Concert Industries Ltd. ("Concert") when it and its Canadian operating subsidiaries announced on August 5, 2003 that it had filed for protection under the Companies' Creditors Arrangement Act ("CCAA"). Concert was restructured and a plan of compromise and arrangement for its operating subsidiaries was approved in December 2004 allowing them to emerge from the CCAA proceedings. Mr. Normand no longer serves as a director of Concert.

(9)

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

(10)

Officers of EnerMark

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

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

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.

Ian C. Dundas Calgary, Alberta, Canada	Senior Vice President, Business Development	Senior Vice President, Business Development since July 2004. Prior thereto, Vice President and Director, Business Development of Enerplus since February 2003. Prior thereto, Vice President of EGEM since August 2001. Prior thereto, Chief Financial Officer of Medmira Inc., (a public biotechnology company).

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 and Senior Vice President of El Paso Merchant Energy (a merchant trading company).

Eric P. Tremblay Calgary, Alberta, Canada	Senior Vice President, Capital Markets	Senior Vice President, Capital Markets of Enerplus.

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).

Jo-Anne M. Caza Calgary, Alberta, Canada	Vice President, Investor Relations	Vice President of Investor Relations of Enerplus.

Name and Residence

Office

Principal Occupation for Past Five Years⁽¹⁾

Rodney D. Gray Calgary, Alberta, Canada	Vice President, Finance	Vice President, Finance of Enerplus since February 2005. Prior thereto, Controller, Finance of Enerplus since June 2002. Prior thereto, independent consultant since September 2001. Prior thereto, Controller and Manager, Financial Reporting with Berkley Petroleum Corp. (an oil and gas exploration and production company)

Larry W. Hammond Calgary, Alberta, Canada	Vice President, Operations	Vice President, Operations of Enerplus since July 2005. Prior thereto, Team Leader with EnCana Corporation (an oil and gas exploration and production company).

David A. McCoy Calgary, Alberta, Canada	Vice President, General Counsel & Corporate Secretary	Vice President, General Counsel & Corporate Secretary of Enerplus since December 2002. Prior thereto, Consultant, Offshore & International Operations, with EnCana Corporation (an oil and gas exploration and production company) since 2002. Prior thereto, Vice President, General Counsel & Government Affairs with Conoco Canada Limited (an oil and gas exploration and production company).

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.

Wayne G. Ford Calgary, Alberta, Canada	Controller, Operations	Controller, Operations of Enerplus since August 2001. Prior thereto, Controller of Argonauts Group Ltd. (an oil and gas exploration and production company).

Jodine J. Jenson Labrie Cochrane, Alberta, Canada	Controller, Finance	Controller, Finance of Enerplus since March 2006. Prior thereto, Manager, Finance and Senior Financial Accountant of Enerplus since September 2003. Prior thereto, 2nd Vice President of American Chartered Bank (a U.S. bank located in Illinois, U.S.A.) since October 2002. Prior thereto, Senior Manager, Financial Advisory Services of KPMG Financial Services Inc. (an accounting and financial services firm).

___________

Note:

(1)

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

As of February 28, 2006, the directors and officers named above beneficially own, directly or indirectly, an aggregate of 415,501 Trust Units, representing approximately 0.35% of the outstanding Trust Units as of that date.

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

Audit Committee Disclosure

The disclosure regarding Enerplus' Audit Committee required under Multilateral Instrument 52-110 adopted by certain of the Canadian securities regulatory authorities is contained in Appendix "E" to this Annual Information Form.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

To the knowledge of the directors and executive officers of EnerMark, none of the directors or executive officers of EnerMark and no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10% of any class or series of the Fund's securities, nor any associate or affiliate of any of the foregoing, has had any material interest, direct or indirect, in any material transaction with Enerplus since January 1, 2003 or in any proposed transaction that would materially affect Enerplus.

MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS

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

A copy of the Trust Indenture, which is described under "Information Respecting Enerplus Resources Fund - Description of the Trust Units and the Trust Indenture", was publicly filed on January 5, 2004 and is available on the Fund's SEDAR profile at www.sedar.com. A copy of the Fund's unitholder rights plan agreement, which is described under "Information Respecting Enerplus Resources Fund - Unitholder Rights Plan", was publicly filed on April 12, 2005 and is available on the Fund's SEDAR profile at www.sedar.com.

INTERESTS OF EXPERTS

Sproule prepared the Sproule Report in respect of the reserves attributable to Enerplus' Canadian conventional oil and natural gas properties, a summary of which is contained in this Annual Information Form. As of the date of the Sproule Report, the "designated professionals" (as defined in Form 51-102F2 - Annual Information Form of the Canadian securities regulatory authorities) of Sproule, as a group, beneficially owned, directly or indirectly, less than 1% of the Fund's outstanding Trust Units. D&M prepared the D&M Report in respect of Enerplus' U.S. conventional oil and natural gas properties, a summary of which is contained in this Annual Information Form. As of the date of the D&M Report, the designated professionals of D&M, as a group, beneficially owned, directly or indirectly, less than 1% of the Fund's outstanding Trust Units. GLJ prepared the GLJ Report in respect of the SAGD reserves attributable to Enerplus' working interest in the Joslyn Project, a summary of which is contained in this Annual Information Form. As of the date of the GLJ Report, the designated professionals of GLJ, as a group, beneficially owned, directly or indirectly, less than 1% of the Fund's outstanding Trust Units.

The auditors of the Fund are Deloitte & Touche LLP, Chartered Accountants, Calgary, Alberta. Deloitte & Touche LLP has confirmed that it is independent with the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

REGISTRAR AND TRANSFER AGENT

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

ADDITIONAL INFORMATION

Additional information relating to the Fund may be found on the Fund's company profile on the SEDAR website at www.sedar.com. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Fund's securities and securities authorized for issuance under equity compensation plans, as applicable, is contained in the Fund's information circular dated February 28, 2006 for its 2006 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 year ended December 31, 2005.

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 Enerplus Resources Fund (the "Company"):

1.	We have evaluated and reviewed the Company's Reserves Data as at December 31, 2005. The Reserves Data consist of the following:

(a)

(i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and

(ii) the related estimated future net revenue; and

(b)

(i) proved oil and gas reserve quantities were estimated as at December 31, 2005 using constant prices and costs; and

(ii) the related estimated future net revenue.

2.	The Reserves Data are the responsibility of the Company'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).

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.

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 Company evaluated by us as of December 31, 2005, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's management and the Board of Directors:

Net Present Value of future Net Revenue

(10% discount rate)

Independent Qualified

Reserves Evaluator or Auditor

Description and

Preparation Date of

Evaluation Report

Location of

Reserves (Country

or Foreign

Geographic Area)

Audited

Evaluated

Reviewed

Total

(in $ millions)

Sproule Associates Limited

Evaluation of the P&NG Reserves of Enerplus Resources Fund, as of December 31, 2005, prepared July, 2005 to January, 2006

Canada

Nil

4,402.9

525.9

4,928.8

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.

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.

A-1

Executed as to our report referred to above:

Sproule Associates Limited Calgary, Alberta, Canada February 28, 2006	/s/ DOUG KING Doug King, P. Eng. Associate

	/s/ HANS J. FIRLA Hans J. Firla, P. Eng. Associate

	/s/ R. KEITH MACLEOD R. Keith MacLeod, P. Eng. Executive Vice-President

	/s/ MICHAEL W. MAUGHAN Michael W. Maughan, C.P.G., P. Geol. Manager, Geoscience & Associate

	/s/ KEN H. CROWTHER Ken H. Crowther, P. Eng. President

A-2

APPENDIX "B"

REPORT ON RESERVES DATA BY INDEPENDENT

QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

To the board of directors of Enerplus Resources Fund (the "Company"):

1.	We have prepared an evaluation of the Company's reserves data as at December 31, 2005. The reserves data consist of the following:

(a)

(i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 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, 2005, using constant prices and costs; and

(ii)

the related estimated future net revenue.

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

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us for the year ended December 31, 2005, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:

Net Present Value of future Net Revenue

(10% discount rate)

Independent Qualified Reserves

Evaluator or Auditor

Description and

Preparation Date of

Evaluation Report

Location of Reserves

(Country or Foreign

Geographic Area)

Audited

Evaluated

Reviewed

Total

(in $ thousands)

GLJ Petroleum Consultants Ltd.

January 20, 2006

Canada

36,282

5.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

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

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:

GLJ Petroleum Consultants Ltd.

Calgary, Alberta, Canada

March 2, 2006

"Dana B. Laustsen"

Dana B. Laustsen, P. Eng.

Executive Vice-President

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APPENDIX "C"

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 Enerplus Resources Fund ("Enerplus"):

1.	Pursuant to the request of Enerplus, we have evaluated and reviewed Lyco Energy Corp.'s reserves data as at December 31, 2005. The reserves data includes the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast (as defined in our report) prices and costs; and

	(ii)	the related estimated future net revenue; and

(b)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using constant (as defined in our report) prices and costs; and

	(ii)	the related estimated future net revenue.

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

3.	Those standards require that we plan and perform an evaluation to assure reserve estimates are free of material misstatement and are in accordance with principles and definitions presented in the COGE Handbook.

The following table sets forth the estimated future net revenue (before deduction of income taxes) in thousands of United States dollars (M$) for proved plus probable reserves evaluated by us, estimated using forecast prices and costs and calculated using a discount rate of 10%, evaluated as of December 31, 2005, and identifies the respective portions thereof that we have evaluated and reported to the Company's management:

Net Present Value of future Net Revenue

(10% discount rate)

Independent Qualified

Reserves Evaluator

or Auditor

Description and

Preparation Date of

Evaluation Report

Location of

Reserves

(Country or

Foreign

Geographic

Area)

Audited

Evaluated

Reviewed

Total

(in US$ thousands)

DeGolyer and MacNaughton

Appraisal Report as of December 31, 2005 on Certain Properties owned by Lyco Energy Corporation

Montana and

North Dakota

Not

Applicable

720,254

Not

Applicable

720,254

5.	In our opinion, the reserves and revenue evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

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

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

C-1

Executed as to our report referred to above:

DeGolyer and MacNaughton Dallas, Texas, USA January 23, 2006	Submitted, "DEGOLYER AND MACNAUGHTON" DeGolyer and MacNaughton

	/s/ PAUL J. SZATKOWSKI Paul J. Szatkowski, P.E. Senior Vice President DeGolyer and MacNaughton

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APPENDIX "D"

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, 2005 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, 2005 using constant prices and costs; and

(ii)

the related estimated future net revenue.

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

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

(a)

reviewed EnerMark's procedures for providing information to the independent qualified reserves evaluators;

(b)

met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

(c)

reviewed the reserves data with management and the independent qualified reserves evaluators.

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

(a)

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

(b)

the filing of the reports of the independent qualified reserves evaluators on the reserves data; and

(c)

the content and filing of this report.

D-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

"Garry A. Tanner"

Garry A. Tanner

Senior Vice President and

Chief Operating Officer

"Harry B. Wheeler"

Harry B. Wheeler

Director

"W.C. (Mike) Seth"

W.C. (Mike) Seth

Director

March 7, 2006

D-2

APPENDIX "E"

AUDIT COMMITTEE DISCLOSURE

PURSUANT TO MULTILATERAL INSTRUMENT 52-110

A.	The Audit & Risk Management Committee's Charter

Set forth below is the charter of the Audit & Risk Management Committee (the "Committee") of the board of directors of EnerMark.

I.	AUTHORITY

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

II.

PURPOSE OF THE COMMITTEE

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

financial reporting and disclosure of the Fund;

the Fund's compliance with regulatory requirements;

external auditors' qualifications, appointment, fees and independence;

evaluating and monitoring the performance of the Fund's external auditors;

preparation of the Fund's continuous disclosure documents; and

monitoring the manner in which the financial risks of the Fund are being managed.

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

III.

COMPOSITION AND COMPETENCY OF THE COMMITTEE

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

IV.

MEETINGS OF THE COMMITTEE

The Committee shall meet with such frequency and of such intervals, as it shall determine is necessary to carry out its duties and responsibilities. As part of its purpose to foster open communications, the Committee shall meet at least quarterly with management and the Fund's external auditors in separate executive sessions to

E-1

discuss any matters that the Committee or each of these groups or persons believes should be discussed privately. The Chairman works with the Chief Financial Officer and external auditors to establish the agendas for Committee meetings, ensuring that each party's expectations are understood and addressed. The Committee, in its discretion, may ask members of management or others to attend its meetings (or portions thereof) and to provide pertinent information as necessary. The Committee shall maintain minutes of its meetings and records relating to those meetings and the Committee's activities and provide copies of such minutes to the Board.

V.	DUTIES AND ACTIVITIES OF THE COMMITTEE

Evaluation and Appointment of External Auditors

Review its charter annually and recommend changes to the Board when necessary;

Make recommendations to the Board on the appointment of external auditors of the Fund and its subsidiaries;

Review and approve the Fund's external auditors' annual engagement letter and audit plans, including the proposed fees contained therein;

Review the performance of the external auditors and make recommendations to the Board regarding their replacement when circumstances warrant. The review shall take into consideration the evaluation made by management of the external auditor's performance. Approve payment of audit fees and pre-approve audit related and other authorized work fees;

Oversee the independence of the external auditors by, among other things;

(a)

requiring the external auditors to deliver to the Committee on a periodic basis a formal written statement delineating all relationships between the external auditors and the Fund;

(b)

reviewing and approving EnerMark's hiring policies regarding partners, employees and former partners and employees of current and formal external auditors;

(c)

actively engaging in a dialogue with the external auditors with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditors and recommending that the Board take appropriate action to satisfy itself of the auditors' independence;

(d)

pre-approve the nature of non-audit related services and the fees thereon;

(e)

conducting private sessions with the external auditors and encouraging direct communications between the Chairman of the Committee and the audit partner; and

(f)

instructing the Fund's external auditors that they are ultimately accountable to the Committee and the Board and that the Committee and the Board are responsible for the selection (subject to unitholder approval), evaluation and termination of the Fund's external auditors.

Oversight of Annual and Quarterly Statements and Management Discussion and Analysis

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

Confirm, through private discussions with the external auditors and management, that no restrictions are being placed on the scope of the external auditors' work;

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

(a)

external auditors' report, the annual and quarterly financial statements, the management's discussion and analysis, Sarbanes-Oxley processes and procedures, the certification process by the CEO and CFO, and any other pertinent reports and management's responses concerning the financial statements;

E-2

(b)

the qualitative judgments of the external auditors about the appropriateness, not just the acceptability, of accounting principles and financial disclosure practices used or proposed to be adopted by the Fund and, particularly, their views about alternate accounting treatments and their effects on the financial results;

(c)

the methods used to account for significant unusual transactions;

(d)

the effect of significant accounting policies in controversial or emerging areas for which there is a lack of authoritative guidance or consensus;

(e)

management's process for formulating sensitive accounting estimates and the reasonableness of these estimates;

(f)

significant recorded and unrecorded audit adjustments;

(g)

any material accounting issues among management and the external auditors;

(h)

other matters required to be communicated to the Committee by the external auditors under generally accepted auditing standards by the external auditors; and

(i)

management's acknowledgement of its responsibility towards the financial statements.

Oversight of Financial Reporting Process, Internal Controls and Certification Process

Establishment of the Fund's Whistleblower Policy for the submission, receipt, retention and treatment of complaints and concerns regarding accounting and auditing matters, and review of any developments and responses on reports received thereunder;

10.

Review the adequacy and effectiveness of the financial reporting system and internal control policies and procedures with the external auditors and management. Ensure that EnerMark complies with all new regulations in this regard;

11.

Review with management EnerMark and the Fund's administrative, operational and accounting internal controls, including controls and security of the computerized information systems, and evaluate whether EnerMark and the Fund are operating in accordance with prescribed policies, procedures and codes of conduct;

12.

Review with management and the external auditors any reportable condition and material weaknesses affecting internal controls;

13.

Receive periodic reports from the external auditors and management to assess the impact of significant accounting or financial reporting developments proposed by the CICA, the AICPA, the Financial Accounting Standards Board, the SEC, the relevant Canadian securities commissions, stock exchanges or other regulatory body, or any other significant accounting or financial reporting related matters that may have a bearing on EnerMark and the Fund;

14.

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

Review of Business Risks

15.

Review with management the list of risks that they have identified and ensure that management has implemented appropriate systems to monitor, mitigate and report such business risks;

16.

Review adequacy of the insurance coverage;

17.

Review the implementation of the Fund's risk management policy;

18.

Review the disclosure of identified risks in the annual disclosure documents sent to Unitholders to ensure that such disclosure meets with regulatory requirements and adequately describes risks to Unitholders;

E-3

Other Matters

19.

Conduct or authorize investigations into any matters within the Committee's scope of responsibilities, including retaining outside counsel or other consultants or experts for this purpose;

20.

Discuss press releases regarding earnings and other financial information provided to analysts and rating agencies;

21.

Review the disclosure made in the Fund's Annual Report, Annual Information Form, Form 40-F and Information Circular regarding the Audit & Risk Management Committee; and

22.

Perform such additional activities, and consider such other matters, within the scope of its responsibilities, as the Committee or the Board deems necessary or appropriate.

VI.

OVERSIGHT OF VARIOUS FINANCIAL EXTERNAL REPORTS

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

VII.

INTERNAL FUNCTIONING OF THE COMMITTEE

Once a year, the Committee reviews the adequacy of its Charter and brings to the attention of the Board required changes, if any, for approval. The Committee will also, annually, make a critical review of its past performance to ensure that it has assumed its responsibilities and executed all required tasks and will suggest changes if it failed to do so. This review will also cover individual members' performance.

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

B.	Composition of the Audit & Risk Management Committee

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

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C.	Relevant Education and Experience

Name (Director Since)		Principal Occupation and Biography

Mr. Robert L. Normand (CA) (June 2001) Other Public Directorships • Quebecor World Inc. (commercial print media services) • Cambior Inc. (gold mining) • Aurizon Mines (gold mining) • ING Canada Ltd. (property and casualty insurance) • Sportscene Group Inc. (chain of restaurants) • Fonds d'Investissement REA (mutual fund)		Mr. Normand is a corporate director and serves on the board of several private and public corporations operating in various fields of the economy, including printing and media, mining and financial. Mr. Normand worked as an external auditor and held accounting responsibilities in two industries before joining Gaz Métropolitain in 1972 where he ultimately held the position of Chief Financial Officer until his retirement in 1997. Mr. Normand is a past President of the Financial Executives Institute Canada and past Vice President of the Financial Executives Institute U.S.

Mr. Glen D. Roane (BA, MBA) (June 2004) Other Public Directorships • Destiny Resource Services Corp. (oil and gas service business) • Badger Income Fund (provider of non-destructive excavation services) • Valiant Energy Inc. (oil and gas producer)		Mr. Roane is a corporate director and serves on the board of several private and public corporations operating primarily in the field of oil and gas production and service businesses. Until 1997, Mr. Roane spent almost twenty years in the Canadian financial services industry, working in increasingly senior roles in corporate banking, investment banking and the management of investments in marketable securities.

Mr. Harry B. Wheeler (BSC (Geology)) (January 2001) Other Public Directorships • Tenergy Ltd. (oil and gas exploration and production)		Mr. Wheeler is the President of Colchester Investments, a private financial corporation. Mr. Wheeler has extensive experience in the oil and gas industry and was operator of his private company before founding Cabre Exploration Ltd. in 1980, and was Chairman of the Board until EnerMark Income Fund acquired Cabre in December 2000. Mr. Wheeler is currently a director of a number of public and private corporations.

D.	Pre-Approval Policies and Procedures

The Committee has implemented a policy restricting the services that may be provided by the Fund's auditors and the fees paid to the Fund's auditors. Prior to the engagement of the Fund's auditors to perform both audit and non-audit services, the Committee pre-approves the provision of the services. In making their determination regarding non-audit services, the Committee considers the compliance with the policy and the provision of non-audit services in the context of avoiding impact on auditor independence. All audit and non-audit fees paid to Deloitte & Touche LLP in 2005 and 2004 were pre-approved by the Committee. Based on the Committee's discussions with management and the independent auditors, the Committee is of the view that the provision of the non-audit services by Deloitte & Touche LLP described above is compatible with maintaining that firm's independence from the Fund.

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E.	External Auditor Service Fees

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

	2005		2004
	(in $ thousands)
Audit fees⁽¹⁾	$	409.2	$	338.7
Audit-related fees⁽²⁾		-		-
Tax fees⁽³⁾		138.5		19.9
All other fees⁽⁴⁾		-		-
	$	547.7	$	358.6

___________

Notes:

(1)	Audit fees were for professional services rendered by Deloitte & Touche LLP for the audit of the Fund's annual financial statements and reviews of the Fund's quarterly financial statements, as well as services provided in connection with statutory and regulatory filings or engagements.

(2)	Audit-related fees are for assurance and related services reasonably related to the performance of the audit or review of the Fund's financial statements and not reported under "Audit fees" above.

(3)	Tax fees were for tax compliance, tax advice and tax planning. The fees were for services performed by the Fund's auditors' tax division except those tax services related to the audit.

(4)	All other fees are fees for products and services provided by the Fund's auditors other than those described as "Audit fees", "Audit-related fees" and "Tax fees".

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Enerplus Resources Fund

The Dome Tower

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

Calgary, Alberta, Canada

T2P 2Z1

Telephone: (403) 298-2200

Fax: (403) 298-2211