Exhibit 99.1

ANNUAL INFORMATION FORM

For the year ended December 31, 2006

March 12, 2007

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS		iii
ABBREVIATIONS AND CONVERSIONS		v
PRESENTATION OF ENERPLUS' OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION		vi
PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION		x
FORWARD-LOOKING STATEMENTS AND INFORMATION		x
STRUCTURE OF ENERPLUS RESOURCES FUND		1
GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND		3
	Historical Overview	3
	Developments in the Past Three Years	3
	Events Subsequent to 2006 Year-End	5
OIL AND NATURAL GAS RESERVES		6
	Overview of Reserves	6
	Summary of Aggregate Enerplus Reserves	7
	Summary of Conventional Oil and Natural Gas Reserves	9
	Summary of Joslyn Project Bitumen Reserves	18
	Reconciliation of Reserves	21
	Reconciliation of Changes in Net Present Value of Future Net Revenue	25
	Undeveloped Reserves	26
	Proved and Probable Reserves Not on Production	27
OPERATIONAL INFORMATION		27
	Overview	27
	Description of Principal Properties and Operations	27
	Summary of Principal Production Locations	37
	Oil and Natural Gas Wells and Unproved Properties	38
	Exploration and Development Activities	38
	Quarterly Production History	39
	Quarterly Netback History	40
	Abandonment and Reclamation Costs	42
	Tax Horizon	42
	Costs Incurred	42
	Marketing Arrangements and Forward Contracts	43
	Environment, Health and Safety	43
	Impact of Environmental Protection Requirements	45
	Additional Operational Information	45
INFORMATION RESPECTING ENERPLUS RESOURCES FUND		46
	Description of the Trust Units and the Trust Indenture	46
	Description of the Royalty Agreements and EnerMark's Subordinated Notes	52
	Management and Corporate Governance	54
	Unitholder Rights Plan	54
DEBT OF ENERPLUS		55
	Bank Credit Facility	55
	Senior Unsecured Notes	56
DISTRIBUTIONS TO UNITHOLDERS		57
	Cash Distributions	57
	Distribution History	58
	Canadian Tax Reporting Matters	58
	U.S. Tax Reporting Matters	58
INDUSTRY CONDITIONS		59
RISK FACTORS		63
MARKET FOR SECURITIES		77
DIRECTORS AND OFFICERS		78
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		81
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS		81
INTERESTS OF EXPERTS		82
REGISTRAR AND TRANSFER AGENT		82
ADDITIONAL INFORMATION		82
APPENDIX "A" — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR		A-1
APPENDIX "B" — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR		B-1
APPENDIX "C" — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR		C-1
APPENDIX "D" — REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION		D-1
APPENDIX "E" — AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE		E-1
APPENDIX "F" — SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION		F-1

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, resources and operations have the meanings set forth under "Presentation of Enerplus' Oil and Gas Reserves, Resources 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 February 1, 2007 and effective December 31, 2006, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus' reserves reporting) dated December 31, 2006;

"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 an indirect 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 an indirect wholly owned subsidiary of the Fund;

"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 an indirect wholly owned subsidiary of the Fund;

"Fund" means Enerplus Resources Fund;

"GAAP" means generally accepted accounting principles;

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

"GLJ Joslyn Resources Report" means the independent engineering evaluation of the contingent resources attributable to Enerplus' interest in the Joslyn Project prepared by GLJ dated February 2, 2007 and effective December 31, 2006;

"GLJ Reserves Report" means the independent engineering evaluation of the reserves attributable to Enerplus' interest in the Joslyn Project prepared by GLJ dated January 29, 2007 and effective December 31, 2006, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus' reserves reporting) dated December 31, 2006;

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

"Income Trust Tax Proposals" has the meaning ascribed thereto under "General Development of the Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts";

"Joslyn Bitumen" means the bitumen produced from the Joslyn Project;

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"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;

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

"North Mine" means the northern portion of the Joslyn Lease, currently designated as a mineable portion of the Joslyn Project;

"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;

"SEC" means the United States Securities and Exchange Commission;

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

"South Mine" means the southern portion of the Joslyn Lease on which potential future bitumen resources have been identified;

"Sproule Report" means the independent engineering evaluation of Enerplus' Canadian conventional oil, NGLs and natural gas interests prepared by Sproule dated February 14, 2007 and effective December 31, 2006, utilizing commodity price forecasts of Sproule dated December 31, 2006;

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

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

"Total" means Total E&P Canada Ltd., a wholly owned subsidiary of Total S.A., which (through its subsidiary, Deer Creek Energy Limited) is the operator of the Joslyn Project;

"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.

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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(1)	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.
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

Note:

(1) A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily at the burner tip and does not represent a value equivalency at the wellhead.

        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

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PRESENTATION OF ENERPLUS'
OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION

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, 2006 and the information contained in the Annual Information Form has been prepared as of March 12, 2007.

        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.

Disclosure of Reserves and Production 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. Furthermore, the estimates of future net revenue attributable to Enerplus' reserves in this Annual Information Form do not give effect to the Income Trust Tax Proposals: see "Oil and Natural Gas Reserves — Overview of Reserves" for additional information.

        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 with reasonable certainty 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 and similar payments, as well as on a "net" basis. 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. As a consequence, Enerplus'

vi

production volumes and reserve estimates may not be comparable to those made by companies utilizing United States disclosure standards. Furthermore, Enerplus has disclosed certain "contingent resources". For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "— Disclosure of Contingent Resources for the Joslyn Project" below.

        Notwithstanding the above, Enerplus has included as Appendix "F" to this Annual Information Form certain disclosure relating to Enerplus' oil and gas reserves and operations in accordance with U.S. Financial Accounting Standards Board's Statement No. 69 — Disclosures About Oil and Gas Producing Activities, which complies with the SEC's guidelines regarding disclosure of oil and gas reserves.

        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.

Disclosure of Contingent Resources for the Joslyn Project

        In this Annual Information Form, Enerplus has disclosed estimated volumes of "contingent resources" that have been prepared by GLJ pursuant to the GLJ Joslyn Resources Report and which relate to certain potential mineable portions of the Joslyn Lease. "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally occurring accumulations but are not capable of being classified as "reserves" as described below. "Contingent resources" is a recognized category of resources in the COGE Handbook and is defined as "those quantities of oil and gas estimated on a given date to be potentially recoverable from known accumulations but are not currently economic". However, as indicated in the COGE Handbook, criteria other than economics may cause a quantity to be classified as a resource rather than a reserve. Section 5 of Volume 2 of the COGE Handbook states that the following issues are contingencies that affect the classification as resources rather than reserves: ownership considerations; drilling requirements; testing requirements; regulatory considerations; infrastructure and market considerations; timing of production and development; and economic requirements. Contingent resources may also include those quantities of hydrocarbons that are estimated to be potentially recoverable using technology that is under development. Resources and contingent resources do not constitute, and should not be confused with, reserves. See "Risk Factors — Risks Related to Enerplus' Business and Operations — Enerplus' actual reserves and resources will vary from its reserve and resource estimates, and those variations could be material."

        There is no certainty that Enerplus will produce any portion of the volumes currently classified as "contingent resources". The primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Joslyn Project as "reserves" consist of current uncertainties around the specific scope of the Joslyn Project (and in particular the finalization of an overall lease development plan), timing of the proposed development as it relates to proposed changes in the lease development plan, proposed reliance on technologies that have not yet been demonstrated to be commercially applicable in oil sands applications, the uncertainty regarding marketing plans for production from the subject areas and improved estimation of project costs. Enerplus believes that development of the Joslyn Project will proceed, including the development of the contingent resources associated with the North Mine and South Mine as disclosed in this Annual Information Form. However, there are a number of inherent risks and contingencies associated with such development, including commodity price fluctuations, project costs and those other risks and contingencies described above and under "Risk Factors" in this Annual Information Form and particularly under "Risk Factors — Risks Related to Enerplus' Business and Operations — The Joslyn Project is in the early development stage and is subject to numerous risks."

Interests in Reserves, Production, Wells and Properties

        In addition to the terms having defined meanings set forth in NI 51-101, the terms set forth below have the following meanings when used in this Annual Information Form:

        "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. See "— Disclosure of Reserves and Production Information" above.

vii

        "gross" 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 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 and Levels of Certainty for Reported Reserves

        "Reserves" are those remaining quantities of oil and gas anticipated to be economically recoverable from known accumulations. Reserves may be divided into proved and probable categories (as well as possible reserves, which Enerplus does not report).

        "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.

        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; and

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

Development and Production Status

        Each of the reserves categories reported by Enerplus (Proved and Probable) 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 

viii

     must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

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

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

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, 2006, held constant throughout the estimated lives of the properties to which the estimate applies; and

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

        "Forecast prices and costs" means future prices and costs that are:

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

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

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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 14 to the Fund's audited consolidated financial statements for the year ended December 31, 2006, which are available on the Fund's SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the Form 6-K filed with the SEC on February 23, 2007, and on Enerplus' website at www.enerplus.com.

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

FORWARD-LOOKING STATEMENTS AND INFORMATION

        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 and/or resources; 

 • crude oil, NGLs, natural gas and bitumen production levels; 

 • commodity prices, foreign currency exchange rates and interest rates; 

 • capital expenditure programs and other future expenditures; 

 • supply and demand for oil, NGLs and natural gas; 

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

 • schedules for and timing of certain projects, including the Joslyn Project, 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; 

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

x

 • changes or fluctuations in oil, NGLs, natural gas and bitumen 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 risks; 

 • actions of industry partners; 

 • uncertainties associated with estimating reserves and resources; 

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

 • incorrect assessments of the value of acquisitions; 

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

 • changes in general economic, market and business conditions in Canada, North America and worldwide; 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, 2006, which is available through the internet on Enerplus' SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the Form 6-K filed with the SEC on February 23, 2007, and on Enerplus' website at www.enerplus.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, on EDGAR at www.sec.gov and on Enerplus' website at www.enerplus.com.

xi

ENERPLUS RESOURCES FUND

Annual Information Form
for the year ended December 31, 2006

STRUCTURE OF ENERPLUS RESOURCES FUND

Enerplus Resources Fund

        Enerplus Resources Fund is an energy 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 its directly and indirectly owned subsidiaries 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, 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 maximize value and cash distributions to its unitholders over the long-term from the net cash flow generated by the operation and development of its Operating Subsidiaries' existing crude oil and natural gas properties and other energy-related assets and the strategic acquisition and rationalization of properties and assets. See "Operational Information — Overview".

Operating Subsidiaries

        The Fund's 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 and contingent bitumen resources 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 securities of each of EnerMark, ERC, Enerplus Oil & Gas, ECT and Enerplus USA are indirectly owned by the Fund.

1

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:

2

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 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 coalbed methane (also known as natural gas from coal) project in central Alberta.

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 created 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 and certain other provinces have adopted similar unitholder liability legislation. 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.

3

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 $5.8 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. This acquisition was accounted for as an asset acquisition in accordance with GAAP.

        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.

Participation in Joslyn Project and Other Oil Sands Projects

        Enerplus initially acquired a 16% working interest in the Joslyn Project in 2002. The remaining 84% working interest is owned by Total, which acquired the original operator and majority owner of the Joslyn Project (Deer Creek Energy Limited) in 2005. Total 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 Energy Limited prior to its acquisition by Total. Included in the sale is an area of mutual interest agreement which has been designed to allow Enerplus and Laricina to jointly pursue additional in-situ oil sands ventures.

S&P/TSX Index Inclusion

        In 2005, Standard and Poor's announced that it would 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 and the remaining one-half weighting occurred in mid-March 2006.

Federal Government Pronouncements on Income Trusts

        On October 31, 2006, the Canadian federal government (the "Government") announced plans to introduce a tax on publicly traded income trusts (other than real estate investment trusts) to generally tax income trusts at the same effective tax rates as Canadian corporations (the "Income Trust Tax Proposals"). For existing income trusts, such as the Fund, the new tax measures would not be effective until 2011, provided that such trusts comply with certain "normal growth" parameters regarding equity growth until that time. Those parameters are designed to ensure that income trusts do not undertake what the Government has deemed to be "undue expansion" in an attempt to circumvent the Government's intention to halt the growth of the income trust industry in Canada. A "Notice of Ways and Means Motion" was passed in the Canadian Parliament shortly after

4

the Government announcement. This notice was a one-page summary of the Income Trust Tax Proposals and it did not identify any specific amendments to the Tax Act.

        On December 15, 2006, the Government announced guidance regarding a "normal growth" safe harbour for future issuances of equity capital. The safe harbour amount will be measured by reference to the individual trust's market capitalization as of the end of trading on October 31, 2006 (which was approximately $7.5 billion for the Fund). For the period from November 1, 2006 to December 31, 2007, a trust's safe harbour amount will be 40 percent of the October 31, 2006 market capitalization benchmark, and for each of the years 2008 through and including 2010 a trust's safe harbour amount will be 20 percent of the benchmark, cumulatively allowing equity growth of up to 100 percent until 2011. In addition, Enerplus understands that income trusts will be able to issue equity to retire debt existing on October 31, 2006 without eroding their safe harbour limits. The guidance regarding "normal growth" is administrative in nature and is not law and can be revised without an Act of the Canadian Parliament.

        On December 21, 2006, the Government released draft legislative proposals to amend the Tax Act with respect to the Income Trust Tax Proposals and requested comments from stakeholders. In late January 2007 the House of Commons Standing Committee on Finance (the "Standing Committee") held special hearings on the Income Trust Tax Proposals and the draft legislation. On February 28, 2007, the Standing Committee released its report that recommended, among other things, that the proposed income trust tax be reduced from 31.5% to 10% with such tax to commence immediately and be refundable to Canadian investors or that the proposed transition period be extended from four years to ten years. The Government is not bound by any of the report recommendations and it is expected that the Government will proceed with the Income Trust Tax Proposals in their original form. As a result, at this time Enerplus is unable to determine the impact, if any, this report may have on the Income Trust Tax Proposals.

        At this time, the draft legislation to give effect to the Income Trust Tax Proposals has not yet been introduced into the Canadian House of Commons and therefore has not been approved or declared in force by the Government. Accordingly, it is uncertain when the proposed legislation could be passed by the Canadian Parliament, if at all, or as to what form, if any, changes in Canadian income tax laws will take as a result of such proposal. Should the proposed tax legislation become substantially enacted, the Fund's future income taxes disclosed in its financial statements may be adjusted to include temporary differences between the accounting and tax bases of the Fund's assets and liabilities. In addition, the reported estimated net present value of future net revenues from Enerplus' oil and natural gas reserves may be adjusted to include an estimate of such revenues on an "after-tax" basis to reflect the impact of the income trust tax. Subject to clarity through the legislative process, Enerplus will assess alternative organizational structures during the four year transition period.

        For additional information, see "Oil and Natural Gas Reserves — Overview of Reserves", "Operational Information — Tax Horizon" and "Risk Factors — Risks Relating to Enerplus' Structure and Ownership of the Trust Units" in this Annual Information Form.

Events Subsequent to 2006 Year-End

Acquisition of Gross Overriding Royalty Interests in U.S.

        On January 31, 2007, Enerplus acquired various gross overriding royalty ("GORR") interests in the state of Wyoming for total consideration of US$52 million (CDN$60 million). This acquisition represents a modest addition to Enerplus' assets in the United States and establishes a new area which Enerplus believes has significant natural gas development potential.

        The subject assets produce natural gas from the EnCana Corporation-operated Jonah gas field in Wyoming, which is one of the largest natural gas fields in the U.S. The acquisition consisted of a GORR of approximately 0.5% on approximately 650 producing natural gas wells in the Jonah field. Enerplus has acquired a net royalty interest that is equivalent to approximately 540 BOE/d of daily production and approximately 2.2 million BOE of Proved Reserves and 2.9 million BOE of Proved plus Probable Reserves based on independent third party engineering evaluations effective December 31, 2006. Enerplus believes the field has a significant number of additional infill drilling locations that will provide growth potential for the future. Enerplus will not be required to expend any future development capital on the assets. Enerplus expects the net operating cash flow per BOE, net of all applicable U.S. taxes, to be significantly higher than that of its existing production due to the nature of the GORR which is not subject to deductions for operating costs and royalties.

5

OIL AND NATURAL GAS RESERVES

Overview of Reserves

        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 90% 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 rate 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 rate assumptions utilized by Sproule.

        The following tables summarize, as at December 31, 2006, Enerplus' oil, NGLs and natural gas reserves and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions associated with such reserve estimates. The following reserves information does not include the various gross overriding royalty interests in Wyoming, U.S.A. acquired by Enerplus on January 31, 2007 as described under "General Development of Enerplus Resources Fund — Events Subsequent to 2006 Year-End — Acquisition of Gross Overriding Royalty Interests in U.S.". 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 of Enerplus' bitumen reserves are located in Canada.

        All estimates of 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 (which currently only consist of income taxes related to U.S. operations). All estimates of future net revenues associated with Enerplus' oil, NGLs and natural gas reserves are presented on the basis that Enerplus will not pay cash income taxes in Canada in the future due to Enerplus' current structure as an income trust and Canadian tax laws currently in effect, and do not give effect to the Income Trust Tax Proposals. Enerplus' U.S. operations are subject to cash income taxes, and as a result Enerplus' U.S. reserves are disclosed net of the taxes Enerplus estimates will be payable after taking into account inter-company debt within Enerplus' structure. The Canadian federal government has announced the Income Trust Tax Proposals which are designed to generally tax income trusts such as Enerplus at the same effective tax rates as Canadian corporations, effective for the 2011 tax year. Such proposals are not yet approved or in force and it is uncertain as to what form, if any, changes in Canadian income tax laws will take as a result of such proposal. Any changes in Canadian income tax laws that may result from the Income Trust Tax Proposals could adversely affect the estimated future net revenues associated with Enerplus' oil and gas reserves. If the draft legislation designed to give effect to the Income Trust Tax Proposals is enacted as currently proposed, Enerplus intends to provide updated reserves information which would present the estimated future net revenues from Enerplus' reserves on an after-tax basis that would reflect the impact of the income trust tax. For additional information, see "General Development of Enerplus Resources Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts", "Operational Information — Tax Horizon" and "Risk Factors — Risks Relating to Enerplus' Structure and Ownership of the Trust Units" in this Annual Information Form.

        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 NGLs 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

6

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, Resources 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 Reserves 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 Reserves 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, 2006

Company Interest Reserves,
Forecast Prices and Costs

	OIL AND GAS NATURAL 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		66,458		28,932		2,479		97,869		11,434		727,596		230,569
United States		21,933		—		—		21,933		—		13,626		24,204
Total		88,391		28,932		2,479		119,802		11,434		741,222		254,773
Proved Developed Non-Producing
Canada		537		—		—		537		621		17,317		4,044
United States		871		—		—		871		—		724		992
Total		1,408		—		—		1,408		621		18,041		5,036
Proved Undeveloped
Canada		3,509		2,221		6,251		11,981		635		160,348		39,341
United States		587		—		—		587		—		450		662
Total		4,096		2,221		6,251		12,568		635		160,798		40,003
Total Proved
Canada		70,504		31,153		8,730		110,387		12,690		905,261		273,954
United States		23,391		—		—		23,391		—		14,800		25,858
Total		93,895		31,153		8,730		133,778		12,690		920,061		299,812
Probable
Canada		16,872		8,912		47,998		73,782		3,777		306,804		128,693
United States		8,637		—		—		8,637		—		37,221		14,840
Total		25,509		8,912		47,998		82,419		3,777		344,025		143,533
Total Proved plus Probable
Canada		87,376		40,065		56,728		184,169		16,467		1,212,065		402,647
United States		32,028		—		—		32,028		—		52,021		40,698
Total		119,404		40,065		56,728		216,197		16,467		1,264,086		443,345

7

Summary of Aggregate Net Present Value
of Future Net Revenue Attributable to Oil and Gas Reserves
As of December 31, 2006

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		6,705		4,479		3,464		2,877		2,489			6,705		4,479		3,464		2,877		2,489
United States		1,064		821		668		565		491			804		624		509		431		375
Total		7,769		5,300		4,132		3,442		2,980			7,509		5,103		3,973		3,308		2,864
Proved Developed Non-Producing
Canada		120		75		56		45		39			120		75		56		45		39
United States		39		29		24		20		16			25		19		16		13		10
Total		159		104		80		65		55			145		94		72		58		49
Proved Undeveloped
Canada		556		385		272		196		142			556		385		272		196		142
United States		22		15		11		8		6			26		16		10		7		5
Total		578		400		283		204		148			582		401		282		203		147
Total Proved
Canada		7,381		4,939		3,792		3,118		2,670			7,381		4,939		3,792		3,118		2,670
United States		1,125		865		703		593		513			855		659		535		451		390
Total Proved Conventional Reserves		8,506		5,804		4,495		3,711		3,183			8,236		5,598		4,327		3,569		3,060
Probable
Canada		2,721		1,242		745		516		387			2,721		1,242		745		516		387
United States		630		333		198		128		88			419		217		126		78		51
Total Probable Conventional Reserves		3,351		1,575		943		644		475			3,140		1,459		871		594		438
Total Proved Plus Probable Conventional Reserves		11,857		7,379		5,438		4,355		3,658			11,376		7,057		5,198		4,163		3,498
BITUMEN RESERVES
Proved Developed Producing		20		16		13		11		10			20		16		13		11		10
Proved Undeveloped		39		20		10		4		1			39		20		10		4		1
Total Proved		59		36		23		15		11			59		36		23		15		11
Probable		453		104		25		2		(8	)		453		104		25		2		(8	)
Total Proved Plus Probable Bitumen Reserves		512		140		48		17		3			512		140		48		17		3
TOTAL CONVENTIONAL RESERVES AND BITUMEN RESERVES		12,369		7,519		5,486		4,372		3,661			11,888		7,197		5,246		4,180		3,501

8

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, 2006

Forecast Prices and Costs

	OIL AND NATURAL GAS RESERVES
	Light & 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		66,458		65,681		60,673		28,932		28,911		25,889		727,596		704,228		587,410
United States		21,933		21,933		18,280		—		—		—		13,626		13,626		11,375
Total		88,391		87,614		78,953		28,932		28,911		25,889		741,222		717,854		598,785
Proved Developed Non-Producing
Canada		537		537		277		—		—		—		17,317		16,897		13,562
United States		871		871		727		—		—		—		724		724		608
Total		1,408		1,408		1,004		—		—		—		18,041		17,621		14,170
Proved Undeveloped
Canada		3,509		3,500		3,184		2,221		2,219		1,890		160,348		156,655		136,033
United States		587		587		493		—		—		—		450		450		377
Total		4,096		4,087		3,677		2,221		2,219		1,890		160,798		157,105		136,410
Total Proved Reserves
Canada		70,504		69,718		64,134		31,153		31,130		27,779		905,261		877,780		737,005
United States		23,391		23,391		19,500		—		—		—		14,800		14,800		12,360
Total		93,895		93,109		83,634		31,153		31,130		27,779		920,061		892,580		749,365
Probable Reserves
Canada		16,872		16,690		15,077		8,912		8,903		8,035		306,804		299,699		253,635
United States		8,637		8,637		7,091		—		—		—		37,221		37,221		30,985
Total		25,509		25,327		22,168		8,912		8,903		8,035		344,025		336,920		284,620
Total Proved Plus Probable Reserves
Canada		87,376		86,408		79,211		40,065		40,033		35,814		1,212,065		1,177,479		990,640
United States		32,028		32,028		26,591		—		—		—		52,021		52,021		43,345
Total		119,404		118,436		105,802		40,065		40,033		35,814		1,264,086		1,229,500		1,033,985

(continues on next page)

9

(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		11,434		11,241		7,978		228,090		223,205		192,441
United States		—		—		—		24,204		24,204		20,175
Total		11,434		11,241		7,978		252,294		247,409		212,616
Proved Developed Non-Producing
Canada		621		606		437		4,044		3,958		2,975
United States		—		—		—		992		992		828
Total		621		606		437		5,036		4,950		3,803
Proved Undeveloped
Canada		635		634		441		33,090		32,462		28,187
United States		—		—		—		662		662		556
Total		635		634		441		33,752		33,124		28,743
Total Proved Reserves
Canada		12,690		12,481		8,856		265,224		259,625		223,603
United States		—		—		—		25,858		25,858		21,559
Total		12,690		12,481		8,856		291,082		285,483		245,162
Probable Reserves
Canada		3,777		3,708		2,665		80,695		79,252		68,049
United States		—		—		—		14,840		14,840		12,256
Total		3,777		3,708		2,665		95,535		94,092		80,305
Total Proved Plus Probable Reserves
Canada		16,467		16,189		11,521		345,919		338,877		291,652
United States		—		—		—		40,698		40,698		33,815
Total		16,467		16,189		11,521		386,617		379,575		325,467

10

Summary of Net Present Value of Future Net Revenue
Attributable to Conventional Oil and Gas Reserves
As of December 31, 2006

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		6,705		4,479		3,464		2,877		2,489		6,705		4,479		3,464		2,877		2,489
United States		1,064		821		668		565		491		804		624		509		431		375
Total		7,769		5,300		4,132		3,442		2,980		7,509		5,103		3,973		3,308		2,864
Proved Developed Non-Producing
Canada		120		75		56		45		39		120		75		56		45		39
United States		39		29		24		20		16		25		19		16		13		10
Total		159		104		80		65		55		145		94		72		58		49
Proved Undeveloped
Canada		556		385		272		196		142		556		385		272		196		142
United States		22		15		11		8		6		26		16		10		7		5
Total		578		400		283		204		148		582		401		282		203		147
Total Proved
Canada		7,381		4,939		3,792		3,118		2,670		7,381		4,939		3,792		3,118		2,670
United States		1,125		865		703		593		513		855		659		535		451		390
Total		8,506		5,804		4,495		3,711		3,183		8,236		5,598		4,327		3,569		3,060
Probable
Canada		2,721		1,242		745		516		387		2,721		1,242		745		516		387
United States		630		333		198		128		88		419		217		126		78		51
Total		3,351		1,575		943		644		475		3,140		1,459		871		594		438
Total Proved Plus Probable
Canada		10,102		6,181		4,537		3,634		3,057		10,102		6,181		4,537		3,634		3,057
United States		1,755		1,198		901		721		601		1,274		876		661		529		441
Total		11,857		7,379		5,438		4,355		3,658		11,376		7,057		5,198		4,163		3,498

11

Summary of Conventional Oil and Gas Reserves
As of December 31, 2006

Constant Prices and Costs

	OIL AND NATURAL GAS RESERVES
	Light & 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		66,969		66,192		61,156		29,050		29,030		25,993		708,394		685,157		571,488
United States		21,898		21,898		18,250		—		—		—		13,602		13,602		11,354
Total		88,867		88,090		79,406		29,050		29,030		25,993		721,996		698,759		582,842
Proved Developed Non-Producing
Canada		541		541		284		—		—		—		17,078		16,641		13,358
United States		870		870		727		—		—		—		723		723		607
Total		1,411		1,411		1,011		—		—		—		17,801		17,364		13,965
Proved Undeveloped
Canada		3,516		3,507		3,188		2,273		2,271		1,937		156,018		152,370		132,615
United States		586		586		492		—		—		—		449		449		377
Total		4,102		4,093		3,680		2,273		2,271		1,937		156,467		152,819		132,992
Total Proved Reserves
Canada		71,026		70,240		64,628		31,323		31,301		27,930		881,490		854,168		717,461
United States		23,354		23,354		19,469		—		—		—		14,774		14,774		12,338
Total		94,380		93,594		84,097		31,323		31,301		27,930		896,264		868,942		729,799
Probable Reserves
Canada		16,928		16,747		15,135		9,038		9,028		8,146		301,380		294,292		249,213
United States		8,660		8,660		7,111		—		—		—		37,212		37,212		30,977
Total		25,588		25,407		22,246		9,038		9,028		8,146		338,592		331,504		280,190
Total Proved Plus Probable Reserves
Canada		87,954		86,987		79,763		40,361		40,329		36,076		1,182,870		1,148,460		966,674
United States		32,014		32,014		26,580		—		—		—		51,986		51,986		43,315
Total		119,968		119,001		106,343		40,361		40,329		36,076		1,234,856		1,200,446		1,009,989

(continues on next page)

12

(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		11,275		11,082		7,866		225,360		220,496		190,262
United States		—		—		—		24,165		24,165		20,143
Total		11,275		11,082		7,866		249,525		244,661		210,405
Proved Developed Non-Producing
Canada		619		602		435		4,006		3,917		2,946
United States		—		—		—		991		991		828
Total		619		602		435		4,997		4,908		3,774
Proved Undeveloped
Canada		632		631		439		32,424		31,804		27,667
United States		—		—		—		660		660		554
Total		632		631		439		33,084		32,464		28,221
Total Proved Reserves
Canada		12,526		12,315		8,740		261,790		256,217		220,875
United States		—		—		—		25,816		25,816		21,525
Total		12,526		12,315		8,740		287,606		282,033		242,400
Probable Reserves
Canada		3,706		3,637		2,612		79,902		78,461		67,429
United States		—		—		—		14,863		14,863		12,274
Total		3,706		3,637		2,612		94,765		93,324		79,703
Total Proved Plus Probable Reserves
Canada		16,232		15,952		11,352		341,692		334,678		288,304
United States		—		—		—		40,679		40,679		33,799
Total		16,232		15,952		11,352		382,371		375,357		322,103

13

Summary of Net Present Value of Future Net Revenue
Attributable to Conventional Oil and Gas Reserves
As of December 31, 2006

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		5,259		3,618		2,816		2,336		2,013		5,259		3,618		2,816		2,336		2,013
United States		1,009		785		639		539		466		775		606		495		418		362
Total		6,268		4,403		3,455		2,875		2,479		6,034		4,224		3,311		2,754		2,375
Proved Developed Non-Producing
Canada		82		54		41		34		29		82		54		41		34		29
United States		36		27		22		18		15		24		17		14		11		10
Total		118		81		63		52		44		106		71		55		45		39
Proved Undeveloped
Canada		356		236		157		103		65		356		236		157		103		65
United States		20		14		10		7		5		26		17		11		8		5
Total		376		250		167		110		70		382		253		168		111		70
Total Proved
Canada		5,697		3,908		3,014		2,473		2,107		5,697		3,908		3,014		2,473		2,107
United States		1,065		826		671		564		486		825		640		520		437		377
Total		6,762		4,734		3,685		3,037		2,593		6,522		4,548		3,534		2,910		2,484
Probable
Canada		1,817		921		581		411		313		1,817		921		581		411		313
United States		478		264		160		103		69		328		176		102		63		39
Total		2,295		1,185		741		514		382		2,145		1,097		683		474		352
Total Proved Plus Probable
Canada		7,514		4,829		3,595		2,884		2,420		7,514		4,829		3,595		2,884		2,420
United States		1,543		1,090		831		667		555		1,153		816		622		500		416
Total		9,057		5,919		4,426		3,551		2,975		8,667		5,645		4,217		3,384		2,836

14

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 includes the following price forecasts supplied by Sproule and the following inflation and exchange rate assumptions:

	CRUDE OIL												NATURAL GAS						NATURAL GAS LIQUIDS
																			Edmonton Par Price
Year	WTI Cushing Oklahoma			Edmonton Par Price 40° API			Hardisty Heavy 12° API			Cromer Medium 29.3° 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)
2007		65.73			74.10			42.98			63.72			7.72			7.85			43.94			55.23			75.88			5.0		0.87
2008		68.82			77.62			45.02			66.75			8.59			8.39			46.03			57.85			79.49			4.0		0.87
2009		62.42			70.25			40.74			60.41			7.74			7.65			41.66			52.36			71.94			3.0		0.87
2010		58.37			65.56			38.03			56.38			7.55			7.48			38.88			48.87			67.14			2.0		0.87
2011		55.20			61.90			35.90			53.24			7.72			7.63			36.71			46.14			63.40			2.0		0.87
Thereafter		+2.0	%		+2.0	%		+2.0	%		+2.0	%		(1	)		(2	)		+2.0	%		+2.0	%		+2.0	%		2.0		0.87

Notes:

(1) Escalation is 1.7% per year until 2017 and 2% per year thereafter.

(2) Escalation is 1.5% per year until 2017 and 2% per year thereafter.

        In 2006, Enerplus received a weighted average price (net of transportation costs but before hedging) of $49.22/bbl for heavy crude oil, $65.91/bbl for light and medium crude oil, $50.90/bbl for NGLs and $6.81/Mcf for natural gas.

Constant Prices and Costs

        The constant price and cost case assumes the continuance of product prices at December 31, 2006 and operating costs projected for 2007, 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 the following prices in effect as at December 31, 2006 and the following inflation and exchange rate assumptions:

CRUDE OIL

NATURAL GAS

NATURAL GAS LIQUIDS

Edmonton Par Price

WTI Cushing Oklahoma

Edmonton Par Price 40° API

Hardisty Heavy 12° API

Cromer Medium 29.3° 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)

Constant

61.05

67.59

40.06

62.45

6.13

5.52

42.06

54.00

71.51

—

0.858

15

Undiscounted Future Net Revenue by Reserves Category

        The undiscounted total future net revenue by reserves category as of December 31, 2006, using both constant and forecast prices and costs, is set forth below:

RESERVES CATEGORY	Revenue		Royalties and Production  Taxes		Operating Costs		Development Costs		Abandonment and Reclamation Costs		Future Net Revenue Before Income Taxes		Income Taxes		Revenue After Income Taxes
	(in $ millions)
Constant Prices and Costs
Proved Reserves
Canada		11,600		1,651		3,711		425		116		5,697		—		5,697
United States		1,581		396		98		15		7		1,065		240		825
Total		13,181		2,047		3,809		440		123		6,762		240		6,522
Proved Plus Probable Reserves
Canada		14,972		2,147		4,725		467		119		7,514		—		7,514
United States		2,369		596		134		88		8		1,543		390		1,153
Total		17,341		2,743		4,859		555		127		9,057		390		8,667
Forecast Prices and Costs
Proved Reserves
Canada		14,793		2,190		4,570		457		195		7,381		—		7,381
United States		1,661		416		98		15		7		1,125		270		855
Total		16,454		2,606		4,668		472		202		8,506		270		8,236
Proved Plus Probable Reserves
Canada		19,928		2,946		6,150		502		228		10,102		—		10,102
United States		2,649		666		133		87		8		1,755		481		1,274
Total		22,577		3,612		6,283		589		236		11,857		481		11,376

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, 2006, 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)		1,198		1,278
	Heavy Oil(a)		456		492
	Natural Gas(b)		1,360		2,022
Proved Plus Probable Reserves	Light and Medium Crude Oil(a)		1,400		1,493
	Heavy Oil(a)		527		566
	Natural Gas(b)		1,668		2,478
United States
Proved Reserves	Light and Medium Crude Oil(a)		671		703
	Heavy Oil(a)		—		—
	Natural Gas(b)		—		—
Proved Plus Probable Reserves	Light and Medium Crude Oil(a)		831		901
	Heavy Oil(a)		—		—
	Natural Gas(b)		—		—

Notes:

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

(b) Including by-products, but excluding solution gas from oil wells.

16

Estimated Production for Estimates of Future Net Revenue

        The volume of company interest production from Proved plus Probable Reserves estimated for 2007 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		Estimated 2007 Aggregate Production		Estimated 2007 Average Daily Production		Estimated 2007 Aggregate Production		Estimated 2007 Average Daily Production
Crude Oil
	Light and Medium Crude Oil	6,125	Mbbls	16,780	bbls/d	4,201	Mbbls	11,509	bbls/d
	Heavy Oil	3,088	Mbbls	8,460	bbls/d	—		—
Total Crude Oil		9,213	Mbbls	25,240	bbls/d	4,201	Mbbls	11,509	bbls/d
Natural Gas Liquids		1,577	Mbbls	4,322	bbls/d	—		—
Total Liquids		10,790	Mbbls	29,562	bbls/d	4,201	Mbbls	11,509	bbls/d
Natural Gas		96,428	MMcf	264,185	Mcf/d	3,183	MMcf	8,722	Mcf/d
Total		26,861	MBOE	73,593	BOE/d	4,731	MBOE	12,962	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
2007		120		115		130		125		120		115		130		125
2008		119		103		132		114		125		108		139		120
2009		69		54		84		66		75		59		92		72
2010		45		33		50		35		51		37		56		40
2011		30		20		30		20		35		23		35		23
Remainder		42		19		41		20		51		24		50		23
Total		425		344		467		380		457		366		502		403

	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)
UNITED STATES
2007		15		15		88		84		15		15		87		83
2008		—		—		—		—		—		—		—		—
2009		—		—		—		—		—		—		—		—
2010		—		—		—		—		—		—		—		—
2011		—		—		—		—		—		—		—		—
Remainder		—		—		—		—		—		—		—		—
Total		15		15		88		84		15		15		87		83

17

Summary of Joslyn Project Bitumen Reserves

        The following tables summarize the reserves volumes and net present value of future net revenue attributable to Enerplus' 15% working interest in the SAGD-recoverable bitumen reserves of the Joslyn Project as of December 31, 2006, including certain assumptions relating to the determination of those reserves and values, as contained in the GLJ Reserves Report. The following estimated reserves are incremental to the estimated contingent resources associated with the North Mine and South Mine portions of the Joslyn Project disclosed below under "Operational Information — Description of Principal Properties and Operations — Oil Sands — Summary of Certain Joslyn Project Contingent Bitumen Resources".

Summary of Enerplus' Interest in the SAGD Bitumen Reserves of the
Joslyn Lease and Net Present Value of Future Net Revenue
As of December 31, 2006

Forecast Prices and Costs

	BITUMEN RESERVES				NET PRESENT VALUE OF FUTURE NET REVENUE BEFORE AND AFTER INCOMES TAXES, DISCOUNTED AT (%/YEAR)
RESERVES CATEGORY	Gross		Net		0%		5%		10%		15%		20%
	(Mbbls)		(Mbbls)		(in $ millions)
Proved Developed Producing		2,479		2,454		20		16		13		11		10
Proved Undeveloped		6,251		6,188		39		20		10		4		1
Total Proved		8,730		8,642		59		36		23		15		11
Probable		47,998		44,701		453		104		25		2		(8	)
Total Proved Plus Probable		56,728		53,343		512		140		48		17		3

Constant Prices and Cost

	BITUMEN RESERVES				NET PRESENT VALUE OF FUTURE NET REVENUE BEFORE AND AFTER INCOMES TAXES, DISCOUNTED AT (%/YEAR)
RESERVES CATEGORY	Gross		Net		0%		5%		10%		15%		20%
	(Mbbls)		(Mbbls)		(in $ millions)
Proved Developed Producing		2,714		2,687		34		27		21		18		15
Proved Undeveloped		6,016		5,702		71		39		23		13		7
Total Proved		8,730		8,389		105		66		44		31		22
Probable		48,149		42,154		530		148		51		18		4
Total Proved Plus Probable		56,879		50,543		635		214		95		49		26

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 exchange rate of Cdn$1.00=US$0.87 and the price and inflation rate forecasts set forth below supplied by Sproule as at December 31, 2006 (but utilized by GLJ for internal consistency in Enerplus' reserves reporting). The forecast net prices for 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. The

18

forecast net prices for Joslyn Bitumen assume the sale of a bitumen-diluent blended product until mid-2008 and a bitumen-synthetic crude oil blend thereafter, as per the operator's current plans.

	CRUDE OIL								NATURAL GAS
Year	WTI Cushing Oklahoma		Edmonton Par Price 40°API		Bow River Medium 24.9°API		Joslyn Bitumen		30 day spot @ AECO		Inflation Rate
	($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/mmbtu)		(%)
2007	65.73		74.10		53.35		34.10		7.72		5.0
2008	68.82		77.62		55.89		33.67		8.59		4.0
2009	62.42		70.25		50.58		27.91		7.74		3.0
2010	58.37		65.56		47.20		25.84		7.55		2.0
2011	55.20		61.90		44.57		24.24		7.72		2.0
Thereafter	+2.0	%	+2.0	%	+2.0	%	(1	)	(2	)	2.0

Notes:

(1)    Escalation is approximately 2.2% per year thereafter.

(2)    Escalation is 1.7% per year until 2017 and 2% per year thereafter.

Constant Prices and Costs

        The constant price and cost case assumes the continuance of product prices at December 31, 2006 and operating costs projected for 2007, and the continuance of current laws and regulations. The constant bitumen price was based on December 31, 2006 posted reference prices and differentials, and was not materially different than the bitumen price derived using the average year differential methodology described in Canadian Securities Administrators Staff Notice 51-315. 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$0.858 and the following prices in effect as at December 31, 2006:

	CRUDE OIL				NATURAL GAS
	WTI Cushing Oklahoma	Edmonton Par Price 40°API	Bow River Medium 24.9°API	Joslyn Bitumen	30 day spot @ AECO
	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/mmbtu)
Constant	61.05	67.59	48.84	29.53	6.13

Undiscounted Future Net Revenue by Reserves Category

  The undiscounted total future net revenue by reserves category as of December 31, 2006, using both constant and forecast prices and costs, is set forth below:

RESERVES CATEGORY	Revenue		Royalties and Production Taxes		Operating Costs		Development Costs		Abandonment and Reclamation Costs		Future Net Revenue Before Income Taxes		Income Taxes		Revenue After Income Taxes
	(in $ millions)
Constant Prices and Costs
Proved Reserves		258		10		115		27		1		105		—		105
Probable Reserves		1,422		177		528		184		3		530		—		530
Total Proved Plus Probable Reserves		1,680		187		643		211		4		635		—		635
Forecast Prices and Costs
Proved Reserves		245		3		151		31		1		59		—		59
Probable Reserves		1,878		139		996		284		6		453		—		453
Total Proved Plus Probable Reserves		2,123		142		1,147		315		7		512		—		512

 

19

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, 2006, 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 Reserves	Bitumen	44	23
Probable Reserves	Bitumen	51	25
Total Proved Plus Probable Reserves	Bitumen	95	48

Estimated Production for Estimates of Future Net Revenue

        The volume of gross production from the Proved plus Probable Reserves in 2007 estimated by GLJ in preparing the estimated net present values of future net revenue is as follows:

Product Type	Estimated 2007 Aggregate Production	Estimated 2007 Average Daily Production
Bitumen	172 Mbbls	471 bbls/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)
2007		9		9		8		8
2008		—		—		10		9
2009		—		—		12		9
2010		—		—		23		16
2011		—		—		1		1
Remainder		18		8		157		26
Total		27		17		211		69

	Forecast Prices and Costs
	Proved Reserves				Proved Plus Probable Reserves
Year	Undiscounted		Discounted at 10%/year		Undiscounted		Discounted at 10%/year
	(in $ millions)
2007		9		9		8		8
2008		—		—		11		9
2009		—		—		13		10
2010		—		—		25		18
2011		—		—		1		1
Remainder		22		10		257		36
Total		31		19		315		82

 

20

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, 2005 to December 31, 2006, by country and in total, using forecast prices and costs.

Reconciliation of Company Interest Reserves

CANADA	Light & 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, 2005		73,249			17,498			90,747			32,901			8,495		41,396			9,453			43,700			53,153
Acquisitions		984			451			1,435			—			—		—			—			—			—
Divestments		(30	)		(5	)		(35	)		—			—		—			(591	)		(2,738	)		(3,329	)
Discoveries		—			1			1			48			18		66			—			—			—
Extensions		1,648			407			2,055			11			9		20			—			6,935			6,935
Technical Revisions		(2,191	)		(2,414	)		(4,605	)		1,058			337		1,395			(132	)		101			(31	)
Economic Factors		226			47			273			58			10		68			—			—			—
Improved Recovery		2,806			887			3,693			327			43		370			—			—			—
Production		(6,188	)		—			(6,188	)		(3,250	)		—		(3,250	)		—			—			—
December 31, 2006		70,504			16,872			87,376			31,153			8,912		40,065			8,730			47,998			56,728

CANADA	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, 2005		13,084			3,539			16,623			952,624			309,572			1,262,196			287,458			124,827			412,285
Acquisitions		160			72			232			5,518			2,219			7,737			2,063			893			2,956
Divestments		(1	)		(1	)		(2	)		(145	)		(13	)		(158	)		(647	)		(2,745	)		(3,392	)
Discoveries		27			8			35			4,095			845			4,940			757			168			925
Extensions		671			217			888			26,180			9,593			35,773			6,693			9,167			15,860
Technical Revisions		372			(62	)		310			(4,956	)		(22,147	)		(27,103	)		(1,717	)		(5,730	)		(7,447	)
Economic Factors		(17	)		(5	)		(22	)		(5,304	)		(1,642	)		(6,946	)		(616	)		(223	)		(839	)
Improved Recovery		30			9			39			23,981			8,377			32,358			7,159			2,336			9,495
Production		(1,636	)		—			(1,636	)		(96,732	)		—			(96,732	)		(27,196	)		—			(27,196	)
December 31, 2006		12,690			3,777			16,467			905,261			306,804			1,212,065			273,954			128,693			402,647

UNITED STATES	Light & 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, 2005		23,595			5,574		29,169			—		—		—		—		—		—
Acquisitions		401			202		603			—		—		—		—		—		—
Divestments		—			—		—			—		—		—		—		—		—
Discoveries		—			—		—			—		—		—		—		—		—
Extensions		440			982		1,422			—		—		—		—		—		—
Technical Revisions		584			37		621			—		—		—		—		—		—
Economic Factors		—			—		—			—		—		—		—		—		—
Improved Recovery		2,122			1,842		3,964			—		—		—		—		—		—
Production		(3,751	)		—		(3,751	)		—		—		—		—		—		—
December 31, 2006		23,391			8,637		32,028			—		—		—		—		—		—

(continues on next page)

21

(continued)

UNITED STATES	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, 2005		—		—		—		13,152			32,946			46,098			25,787			11,065			36,852
Acquisitions		—		—		—		341			230			571			458			240			698
Divestments		—		—		—		—			—			—			—			—			—
Discoveries		—		—		—		—			—			—			—			—			—
Extensions		—		—		—		384			1,095			1,479			504			1,164			1,668
Technical Revisions		—		—		—		1,732			(1,002	)		730			872			(129	)		743
Economic Factors		—		—		—		—			—			—			—			—			—
Improved Recovery		—		—		—		1,364			3,952			5,316			2,350			2,500			4,850
Production		—		—		—		(2,173	)		—			(2,173	)		(4,113	)		—			(4,113	)
December 31, 2006		—		—		—		14,800			37,221			52,021			25,858			14,840			40,698

TOTAL ENERPLUS	Light & 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, 2005		96,844			23,072			119,916			32,901			8,495		41,396			9,453			43,700			53,153
Acquisitions		1,385			653			2,038			—			—		—			—			—			—
Divestments		(30	)		(5	)		(35	)		—			—		—			(591	)		(2,738	)		(3,329	)
Discoveries		—			1			1			48			18		66			—			—			—
Extensions		2,088			1,389			3,477			11			9		20			—			6,935			6,935
Technical Revisions		(1,607	)		(2,377	)		(3,984	)		1,058			337		1,395			(132	)		101			(31	)
Economic Factors		226			47			273			58			10		68			—			—			—
Improved Recovery		4,928			2,729			7,657			327			43		370			—			—			—
Production		(9,939	)		—			(9,939	)		(3,250	)		—		(3,250	)		—			—			—
December 31, 2006		93,895			25,509			119,404			31,153			8,912		40,065			8,730			47,998			56,728

TOTAL ENERPLUS	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, 2005		13,084			3,539			16,623			965,776			342,518			1,308,294			313,245			135,892			449,137
Acquisitions		160			72			232			5,859			2,449			8,308			2,521			1,133			3,654
Divestments		(1	)		(1	)		(2	)		(145	)		(13	)		(158	)		(647	)		(2,745	)		(3,392	)
Discoveries		27			8			35			4,095			845			4,940			757			168			925
Extensions		671			217			888			26,564			10,688			37,252			7,197			10,331			17,528
Technical Revisions		372			(62	)		310			(3,224	)		(23,149	)		(26,373	)		(845	)		(5,859	)		(6,704	)
Economic Factors		(17	)		(5	)		(22	)		(5,304	)		(1,642	)		(6,946	)		(616	)		(223	)		(839	)
Improved Recovery		30			9			39			25,345			12,329			37,674			9,509			4,836			14,345
Production		(1,636	)		—			(1,636	)		(98,905	)		—			(98,905	)		(31,309	)		—			(31,309	)
December 31, 2006		12,690			3,777			16,467			920,061			344,025			1,264,086			299,812			143,533			443,345

22

Reconciliation of Net Reserves

CANADA	Light & 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, 2005		66,427			14,967			81,394			29,365			6,131		35,496			9,358			41,150			50,508
Acquisitions		921			424			1,345			—			—		—			—			—			—
Divestments		(29	)		(5	)		(34	)		—			—		—			(532	)		(2,597	)		(3,129	)
Discoveries		—			—			—			40			16		56			—			—			—
Extensions		1,452			362			1,814			10			8		18			—			6,519			6,519
Technical Revisions		(1,952	)		(1,489	)		(3,441	)		796			1,838		2,634			(184	)		(371	)		(555	)
Economic Factors		182			21			203			48			9		57			—			—			—
Improved Recovery		2,517			797			3,314			250			33		283			—			—			—
Production		(5,384	)		—			(5,384	)		(2,730	)		—		(2,730	)		—			—			—
December 31, 2006		64,134			15,077			79,211			27,779			8,035		35,814			8,642			44,701			53,343

CANADA	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, 2005		9,107			2,470			11,577			766,200			252,478			1,018,678			241,957			106,798			348,755
Acquisitions		123			62			185			4,162			1,737			5,899			1,738			775			2,513
Divestments		(1	)		—			(1	)		(107	)		(10	)		(117	)		(579	)		(2,604	)		(3,183	)
Discoveries		18			6			24			2,847			592			3,439			533			120			653
Extensions		461			153			614			20,007			7,436			27,443			5,258			8,281			13,539
Technical Revisions		289			(28	)		261			103			(14,856	)		(14,753	)		(1,036	)		(2,524	)		(3,560	)
Economic Factors		(17	)		(5	)		(22	)		(4,070	)		(1,319	)		(5,389	)		(465	)		(196	)		(661	)
Improved Recovery		21			7			28			22,347			7,577			29,924			6,512			2,100			8,612
Production		(1,145	)		—			(1,145	)		(74,484	)		—			(74,484	)		(21,673	)		—			(21,673	)
December 31, 2006		8,856			2,665			11,521			737,005			253,635			990,640			232,245			112,750			344,995

UNITED STATES	Light & 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, 2005		19,815			4,673			24,488			—		—		—		—		—		—
Acquisitions		333			167			500			—		—		—		—		—		—
Divestments		—			—			—			—		—		—		—		—		—
Discoveries		—			—			—			—		—		—		—		—		—
Extensions		367			787			1,154			—		—		—		—		—		—
Technical Revisions		371			(33	)		338			—		—		—		—		—		—
Economic Factors		—			—			—			—		—		—		—		—		—
Improved Recovery		1,727			1,497			3,224			—		—		—		—		—		—
Production		(3,113	)		—			(3,113	)		—		—		—		—		—		—
December 31, 2006		19,500			7,091			26,591			—		—		—		—		—		—

(continues on next page)

23

(continued)

UNITED STATES	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, 2005		—		—		—		11,044			27,655			38,699			21,656			9,282			30,938
Acquisitions		—		—		—		283			191			474			380			199			579
Divestments		—		—		—		—			—			—			—			—			—
Discoveries		—		—		—		—			—			—			—			—			—
Extensions		—		—		—		321			896			1,217			420			937			1,357
Technical Revisions		—		—		—		1,405			(968	)		437			605			(194	)		411
Economic Factors		—		—		—		—			—			—			—			—			—
Improved Recovery		—		—		—		1,111			3,211			4,322			1,912			2,032			3,944
Production		—		—		—		(1,804	)		—			(1,804	)		(3,414	)		—			(3,414	)
December 31, 2006		—		—		—		12,360			30,985			43,345			21,559			12,256			33,815

TOTAL ENERPLUS	Light & 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, 2005		86,242			19,640			105,882			29,365			6,131		35,496			9,358			41,150			50,508
Acquisitions		1,254			591			1,845			—			—		—			—			—			—
Divestments		(29	)		(5	)		(34	)		—			—		—			(532	)		(2,597	)		(3,129	)
Discoveries		—			—			—			40			16		56			—			—			—
Extensions		1,819			1,149			2,968			10			8		18			—			6,519			6,519
Technical Revisions		(1,581	)		(1,522	)		(3,103	)		796			1,838		2,634			(184	)		(371	)		(555	)
Economic Factors		182			21			203			48			9		57			—			—			—
Improved Recovery		4,244			2,294			6,538			250			33		283			—			—			—
Production		(8,497	)		—			(8,497	)		(2,730	)		—		(2,730	)		—			—			—
December 31, 2006		83,634			22,168			105,802			27,779			8,035		35,814			8,642			44,701			53,343

TOTAL ENERPLUS	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, 2005		9,107			2,470			11,577			777,244			280,133			1,057,377			263,613			116,080			379,693
Acquisitions		123			62			185			4,445			1,928			6,373			2,118			974			3,092
Divestments		(1	)		—			(1	)		(107	)		(10	)		(117	)		(579	)		(2,604	)		(3,183	)
Discoveries		18			6			24			2,847			592			3,439			533			120			653
Extensions		461			153			614			20,328			8,332			28,660			5,678			9,218			14,896
Technical Revisions		289			(28	)		261			1,508			(15,824	)		(14,316	)		(431	)		(2,718	)		(3,149	)
Economic Factors		(17	)		(5	)		(22	)		(4,070	)		(1,319	)		(5,389	)		(465	)		(196	)		(661	)
Improved Recovery		21			7			28			23,458			10,788			34,246			8,424			4,132			12,556
Production		(1,145	)		—			(1,145	)		(76,288	)		—			(76,288	)		(25,087	)		—			(25,087	)
December 31, 2006		8,856			2,665			11,521			749,365			284,620			1,033,985			253,804			125,006			378,810

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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, 2005 to December 31, 2006 using constant prices and costs and discounted at 10% per year.

Canada		Year Ended December 31, 2006
		(in $ millions)
Period and Factor
Estimated Future Net Revenue at December 31, 2005		4,827
	Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties	(816	)
	Net Change in Prices, Production Costs and Royalties Related to Future Production	(1,928	)
	Changes in Previously Estimated Development Costs Incurred During the Period	166
	Changes in Estimated Future Development Costs	(206	)
	Net Change Resulting from Extensions and Improved Recovery	665
	Net Change Resulting from Discoveries	11
	Changes from Acquisitions of Reserves	17
	Changes from Dispositions of Reserves	(3	)
	Net Change Resulting from Revisions in Quantity Estimates	(54	)
	Accretion of Discount	379
	Net Changes in Income Taxes	—
Estimated Future Net Revenue at December 31, 2006		3,058

United States		Year Ended December 31, 2006
		(in $ millions)
Period and Factor
Estimated Future Net Revenue at December 31, 2005		579
	Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties	(212	)
	Net Change in Prices, Production Costs and Royalties Related to Future Production	(35	)
	Changes in Previously Estimated Development Costs Incurred During the Period	74
	Changes in Estimated Future Development Costs	(4	)
	Net Change Resulting from Extensions and Improved Recovery	49
	Net Change Resulting from Discoveries	—
	Changes from Acquisitions of Reserves	14
	Changes from Dispositions of Reserves	—
	Net Change Resulting from Revisions in Quantity Estimates	(76	)
	Accretion of Discount	63
	Net Changes in Income Taxes	68
Estimated Future Net Revenue at December 31, 2006		520

(continues on next page)

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(continued)

Total Enerplus		Year Ended December 31, 2006
		(in $ millions)
Period and Factor
Estimated Future Net Revenue at December 31, 2005		5,406
	Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties	(1,028	)
	Net Change in Prices, Production Costs and Royalties Related to Future Production	(1,963	)
	Changes in Previously Estimated Development Costs Incurred During the Period	240
	Changes in Estimated Future Development Costs	(210	)
	Net Change Resulting from Extensions and Improved Recovery	714
	Net Change Resulting from Discoveries	11
	Changes from Acquisitions of Reserves	31
	Changes from Dispositions of Reserves	(3	)
	Net Change Resulting from Revisions in Quantity Estimates	(130	)
	Accretion of Discount	442
	Net Changes in Income Taxes	68
Estimated Future Net Revenue at December 31, 2006		3,578

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
2006	282	2,551	—	150	31.0	8,150

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
2006	39	1,052	6,935	90	13.0	10,283

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

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Proved and Probable Reserves Not on Production

        Enerplus has approximately 7,729 MBOE of Proved plus Probable Reserves which are capable of production but which, as of December 31, 2006, 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 cash distributions to unitholders 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, along with 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 crude oil waterfloods, shallow natural gas, coalbed methane and bitumen in western Canada and Bakken oil development in Montana and North Dakota. Enerplus also invests in the 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 aspects justify the risk to Enerplus. 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, 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 mitigation is important 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, an active price risk management program and other risk mitigation actions. Enerplus typically experiences a greater than 99% drilling success by avoiding a large component of higher risk exploration type drilling. Enerplus also tends to take smaller working interests in higher risk play types to limit exposure in any one well without sacrificing the ability to participate in attractive areas such as the Deep Basin or the Foothills areas of Alberta. However, Enerplus generally allocates approximately 15% to 20% of its annual capital expenditures to longer-term opportunities in oil sands, land, seismic and higher risk drilling activities.

Description of Principal Properties and Operations

        Outlined below is a description of Enerplus' oil and natural gas operations and 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 Reserves

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Report or D&M Report, as applicable, using forecast prices and costs. See "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information".

        All of 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, North Dakota and, since January 31, 2007, Wyoming. All of Enerplus' major properties have related field production facilities and infrastructure to accommodate Enerplus' production. Production volumes for the year ended December 31, 2006 from Enerplus' properties consisted of approximately 47% crude oil and NGLs and 53% natural gas on a BOE basis. Enerplus' 2006 production was comprised of average daily production of 36,134 bbls/d of crude oil, 4,483 bbls/d of NGLs and 271.0 MMcf/d of natural gas for a total of 85,779 BOE/d, an increase of 8% on a BOE basis when compared to 2005 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. Approximately 64% of Enerplus' 2006 production was operated by Enerplus and the remaining 36% was operated by industry partners. As at December 31, 2006, the oil and natural gas property interests held by Enerplus were estimated to contain Proved plus Probable Reserves of 119.4 MMbbls of light and medium crude oil, 40.1 MMbbls of heavy crude oil, 56.7 MMbbls of bitumen, 16.5 MMbbls of NGLs and 1,264.1 Bcf of natural gas, for a total of 443.3 MMBOE. See "Oil and Natural Gas Reserves".

        Enerplus' operations are organized into a business unit structure with five geographically distinct business units. Within each business unit, there are two or three teams of engineers, geologists, landmen and other technical support staff focused on segmented areas within the business unit. Enerplus believes that this structure has enabled it to better focus its activities, improve its operational and technical performance and enhance the generation and execution of attractive capital investment opportunities.

        Enerplus' acquisition and development activities are generally focused on "resource plays", which are typically large and aerially 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 relatively predictable production and decline profiles, the timing, cost, production rates and reserve additions associated with the resource play can be more accurately predicted. Production from resource plays generally exhibits low declines over the long term, with a long reserve life. Enerplus' resource plays include shallow natural gas and coalbed methane in southeast and central Alberta and southwest Saskatchewan, 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.

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Shallow Natural Gas and Coalbed Methane

        Shallow natural gas has been a core development area for Enerplus since the late 1990s. The shallow natural gas formations in southern Alberta and southwest Saskatchewan consist of massive, tightly packed sandstone that covers an area of over 10,000 square kilometres. These zones are typically less than 800 metres in depth and upper Cretaceous in age, with most production coming from the Milk River, Medicine Hat, and Second White Specks producing zones.

        Enerplus has been investing in coalbed methane ("CBM") assets since 2004. Alberta contains significant amounts of coal distributed throughout the southern Plains, Foothills, and Mountain regions. The major coal zones in the Plains region are found in the Scollard (or Ardley), Horseshoe Canyon, Belly River, and Mannville geological zones, or strata. Enerplus is currently focused on the Horseshoe Canyon formation in the Trochu, Bashaw and Joffre areas in Alberta's southern Plains region, which do not have the water handling issues often associated with CBM production.

        Shallow natural gas and CBM are similar resource plays in that the key to success with each is the ability to execute large, multi-well development programs efficiently and to manage the post-drilling operations of these low pressure wells.

        Approximately 16% of Enerplus' production for the year ended December 31, 2006 and approximately 22% of Enerplus' estimated Proved plus Probable Reserves as at December 31, 2006 were comprised of shallow natural gas and CBM. Approximately 67% of this production is operated by Enerplus. In 2006, Enerplus' five largest shallow natural gas producing properties were the Bantry, Hanna Garden, Verger, Shackleton, Medicine Hat South and Countess properties, while its largest CBM producing areas were Bashaw, Trochu and Joffre, all of which are located in Alberta with the exception of Shackleton, which is in southwest Saskatchewan. All of these properties have associated pipeline infrastructure and compression facilities.

        Enerplus invested approximately $94 million in its shallow natural gas and CBM assets in 2006 to drill 430 gross (249.5 net) wells. The majority of this investment occurred at Enerplus' Hanna Garden, Shackleton, Bantry and Medicine Hat shallow natural gas properties and its Joffre, Bashaw and Trochu CBM properties. Enerplus originally planned to invest $123 million in these properties in 2006 but deferred some of this program due to inflationary pressures and weaker natural gas prices. In 2007, Enerplus currently plans to invest approximately

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$43 million in these assets to drill approximately 360 gross (150 net) wells. Enerplus has chosen to reduce investment on shallow natural gas and CBM projects in 2007 as compared to 2006 due to uncertainty on near-term natural gas prices and the desire to maintain investment levels on crude oil projects.

Waterflood Crude Oil

        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 more predictable and stable declines and higher recovery of reserves. Infill drilling and well/injector optimization are effective methods of enhancing reserve recovery even further. Approximately 20% of Enerplus' production for the year ended December 31, 2006 and approximately 24% of Enerplus' estimated Proved plus Probable Reserves as at December 31, 2006 were related to waterflood assets. In 2006, Enerplus' five largest waterflood producing properties were Joarcam, Pembina 5 Way, Giltedge, the Medicine Hat Glauconitic C Unit and Mitsue, all of which are located in Alberta. All of Enerplus' major waterflood areas have associated crude oil production installations for emulsion treating and injection or water disposal. In addition, the Joarcam property also has facilities for natural gas compression, dehydration and processing.

        Enerplus invested $65.8 million on waterflood development in 2006 including participation in the drilling of 40 gross (29.7 net) wells and related infrastructure, facility/injector optimization and re-completions. The majority of this investment occurred at Enerplus' five largest waterflood properties described above.

        In 2007, Enerplus currently plans to invest approximately $65 million on waterflood projects to drill 76 gross (41 net) wells, which is consistent with Enerplus' investment in this play type in 2005 and 2006.

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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 separate acquisitions of Lyco Energy Corporation 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 (42^o API) and some associated natural gas. As Enerplus' single largest producing property, the Sleeping Giant project represented approximately 13% of Enerplus' production in 2006 and 9% of Enerplus' Proved plus Probable Reserves as at December 31, 2006. The property is predominantly operated by Enerplus.

        During 2006 Enerplus invested $116.7 million to drill 41 gross (26.5 net) wells. While the majority of these wells were spaced at two wells per section, Enerplus initiated an increased density drilling program by drilling 6 gross (4 net) "third well per section" wells. Based upon results to date, ten additional increased density wells have been planned for 2007 and continued success may lead to additional increased density wells.

        In 2007, Enerplus plans to invest approximately $70 million in this resource play to drill 26 gross (17 net) oil wells and re-fracture stimulate 12 gross (8 net) wells. Development activity in 2007 will complete the second well per section program in the primary Bakken field area and focus on identifying and proving up new opportunities in the general area. Enerplus owns approximately 114,000 net acres of undeveloped land in Montana and North Dakota, portions of which it plans to test in 2007. The primary target on the undeveloped lands is the Bakken formation, however the lands are also prospective for the Ratcliffe, Mission Canyon, Birdbear, Duperow and Red River geological formations. Key focus areas for Enerplus include: (i) expanding the existing primary Bakken field boundaries including drilling a trendline Bakken exploration well on its lands in North Dakota and evaluating/testing the Glacier area northwest of its current primary field area; (ii) proving up additional increased density drilling opportunities; (iii) accelerating its successful re-fracturing program; (iv) exploring the Bakken and other formations in Montana and North Dakota including completing a seismic program over a portion of the Montana lands with the intent to drill Red River development and exploration wells; and (v) evaluating longer term potential which may include improved recovery via potential waterflood or gas injection.

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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 Limited. In 2005, Deer Creek Energy Limited was acquired by Total, a wholly owned subsidiary of Total S.A., a major international oil and gas company with experience in the extraction and refining of heavy oil. Total is the operator of the Joslyn Project and intends to recover the bitumen located on the Joslyn Lease through a combination of phased SAGD and mining development. In 2006, Enerplus sold a 1% working interest in the Joslyn Project in exchange for equity in Laricina Energy Ltd. ("Laricina"), a private oil sands focused company led by the former Chief Executive Officer of Deer Creek Energy Limited. Included in the sale is an area of mutual interest agreement which has been designed to allow Enerplus and Laricina to jointly pursue additional in-situ oil sands ventures. Following the sale to Laricina, Enerplus now has a 15% working interest in the Joslyn Project.

        Enerplus believes that oil sands production will represent an increasing proportion of its production in the future. Enerplus is progressing on both SAGD and mine development at the Joslyn Lease and is currently one of the only conventional oil and gas income trusts participating in long term development of oil sands through either SAGD or mining. Enerplus has developed an internal oil sands team with significant industry experience which is supporting the development of the Joslyn Lease and also pursuing new grassroots efforts independently and in conjunction with Laricina. In support of these efforts, Enerplus invested approximately $3 million in 2006 to acquire a non-operated working interest in several land positions with in-situ thermal development potential with Laricina. Enerplus has budgeted $6 million in 2007 to further delineate these lands in early 2007.

        In 2006, Enerplus spent approximately $36.1 million at the Joslyn Lease to advance both the SAGD ($33.1 million) and the mining ($3 million) developments. Activity included the drilling of approximately 280 gross additional delineation wells over both SAGD and mining areas, including an additional 4.5 sections of land acquired in late 2005. Capital was invested to advance the progress of the SAGD development including the

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completion of central plant facilities, the commissioning and start-up of the water treatment system and the initiation of steam injection into SAGD well pairs.

Joslyn SAGD Operations

        SAGD Phase I of the Joslyn Project consisted of a pilot project facility and a single well pair which commenced production (to a maximum of 200 bbls/d on a gross basis (30 bbls/d net to Enerplus)) in 2004 and was designed to provide useful information for the future operations of SAGD Phase II. The 10,000 bbls/d (1,500 bbls/d net to Enerplus) SAGD Phase II project (which now includes the single well pair previously forming SAGD Phase I) was scheduled for start-up (i.e. initial steaming) in the first half of 2006. The start-up of Phase II well pairs was delayed by a steam to surface incident that occurred on May 18, 2006. However, by December 31, 2006 more than one half of the well pairs were receiving steam and bitumen production volumes continue to increase. This delay did not affect Enerplus' corporate production guidance for 2006 as Enerplus did not expect any commercial production volumes in 2006. Based on information provided by Total, as the operator of the Joslyn Project, Enerplus continues to expect SAGD Phase II to reach peak production of 10,000 bbls/d (gross) in 2008. However due to reduced operating pressures, this may require additional wells to be drilled and capital expenditures to be made in 2007 and 2008. Enerplus' 2007 capital spending on the SAGD operations is currently budgeted at $21 million, which includes the continued start-up and ramp up of SAGD Phase II well pairs, and the possible addition of new well pairs late in the year.

        The regulatory approval process continues for Phase III of the SAGD development, as the operator responded to additional Supplemental Information Requests by regulators in the fourth quarter of 2006. Enerplus expects regulatory approval for SAGD Phase III to occur in the second quarter of 2007. Currently, SAGD Phase III represents a proposed 15,000 bbls/d expansion of the existing facilities to a potential of 25,000 bbls/d of gross SAGD production. A portion of the SAGD Phase III volumes are currently booked as Probable Reserves by Enerplus. If current development plans are modified and a decision is made to instead mine some of the identified SAGD areas, Enerplus' existing SAGD Phase III Probable Reserve bookings could be impacted. Although Enerplus believes that mining typically provides approximately twice the recovery of the original bitumen in place as compared to SAGD projects, there could be timing differences between reserves bookings associated with the existing SAGD Phase III development plans versus possible expansion of mine development plans.

        Enerplus and Total are continuing to review the optimal lease development and bitumen resource recovery plan given the flexibility which exists for both SAGD and mining operations. Although meaningful progress was made in 2006, the complexities of determining the optimal development plan have extended the timeline anticipated. Enerplus expects an extensive full lease development plan to be completed in 2007. Enerplus does not expect this to impact current SAGD operations or the timing for start-up of the initial phase of the mine.

Joslyn Mining Operations

        Development of the mining portion of the Joslyn Project progressed in 2006 with the filing for regulatory approval for development of the mining resources located in the North Mine in February 2006. Total is currently working on responses to the first round of Supplemental Information Requests from the regulators and Enerplus expects Total to file an update early in the second quarter of 2007. Under current plans, the North Mine represents 100,000 bbls/d of gross bitumen production (15,000 bbls/d net to Enerplus) at a currently estimated cost of approximately $500 million, net to Enerplus.

        Additional future mineable bitumen resources have been identified by Total on the South Mine portion of the Joslyn Lease. However, no regulatory applications have yet been filed with respect to the development of the South Mine. At this time, Enerplus estimates the future development of the South Mine to cost approximately $500 million, net to Enerplus.

        Based on information provided by Total, Enerplus continues to expect start-up of the North Mine in 2013 with peak production expected in 2014, with start-up of the South Mine currently anticipated in 2016 and full production expected in 2017. Enerplus expects its 2007 capital spending to be approximately $13 million to progress the regulatory approval process, engineering and additional delineation of the mining development.

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        Enerplus currently recognizes certain portions of the Joslyn mining operations as contingent resources but expects to eventually classify certain of the contingent resources as Probable Reserves as more uncertainties around the Joslyn Project are resolved. This would result in Enerplus including additional Probable Reserves (and the corresponding future development capital) associated with the Joslyn Project in its future reserves reporting. The timing of such reclassification as reserves remains uncertain, and may extend past 2007. Key factors impacting the timing of future reserves bookings include confirmation of project timing and sanction, regulatory approvals, project scope and marketing plans for the lease. However, a determination of those reserves or the value associated with those reserves cannot be made at this time.

        As a result of the factors described above, no assurance can be provided as to the specific details surrounding the future development of the North Mine or the South Mine.

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

Sanctioned Projects	Joslyn Project Production/ Throughput	Net Production/ Throughput(1)	Estimated Net Future Development Capital(1)	Start Up(2)	Full Production/ Throughput(3)
	(bbls/d)	(bbls/d)	($ millions)
SAGD Phase I and II	10,000	1,500	31	2006	2008
Future Development Projects
SAGD Phase III	15,000	2,250	284	TBD	TBD
North Mine	100,000	15,000	500	2013	2014
South Mine	100,000	15,000	500	2016	2017

Notes:

(1) The net information presented in this table reflects Enerplus' 15% working interest. GLJ's estimates of SAGD production may vary from Total's estimates of production described above.

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

(3) Full production refers to full project production/throughput.

Summary of Certain Joslyn Project Contingent Bitumen Resources

For additional information regarding the disclosure of the contingent resources associated with the Joslyn Project, see "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information — Disclosure of Contingent Resources for the Joslyn Project".

        GLJ, a private independent petroleum consulting firm based in Calgary, Alberta, has evaluated, estimated and subsequently prepared the GLJ Joslyn Resources Report with respect to the contingent bitumen resources associated with Enerplus' 15% interest in the Joslyn Project in accordance with the standards contained in the COGE Handbook. The GLJ Joslyn Resources Report has provided the contingent resource estimates on a bitumen basis rather than a synthetic crude oil basis as, at present, the most likely development scenario will produce a fungible bitumen product that does not require an upgrader solution. However, Total, as the operator of the Joslyn Project, continues to evaluate an upgrader solution for the Joslyn Project.

        The estimated volumes set forth below are associated with two separate mine development decisions, being the North Mine and the South Mine, and consequently such contingent resources are not likely to be reclassified as reserves at the same time. At this time, Enerplus does not intend to disclose any estimates of the contingent resources associated with other potentially mineable portions of the Joslyn Lease. The North Mine and the South Mine have been identified by Total as the projects most likely to proceed in the near-term, with significant uncertainty surrounding the development of additional mineable areas.

       The operator of the Joslyn Project and Enerplus are considering an optimal development plan for the Joslyn Project which may result in a decision to mine the SAGD Phase III areas, to which GLJ has assigned approximately 300 MMbbls of Proved plus Probable gross lease reserves (45 MMbbls net to Enerplus' interest, which reserves are included in Enerplus' reported reserves under "Oil and Gas Reserves — Summary of Joslyn Project Bitumen Reserves" above). However, if this decision is made, Enerplus anticipates that this would likely result in the designation of an additional "West" mining area where Enerplus anticipates that, at a minimum, these same volumes would be recovered. None of the estimated contingent resources relating to the North or South Mines presented herein correspond to the area of the Joslyn Project currently proposed for SAGD development to which reserves have been assigned.

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        The contingent resource estimates for the North Mine and South Mine set forth below are presented as "Low", "Best" and "High" estimates of recoverable volumes, with the "Low" estimate considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation, the "Best" estimate considered to be the best estimate, and the "High" estimate considered to be an optimistic estimate. The "Low", "Best" and "High" estimates reflect some comparability with the reserves categories of "Proved", "Proved plus Probable" and "Proved plus Probable plus Possible", respectively. The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein.

	Contingent Bitumen Resources
		Gross Lease			Company Gross
Mine		Low	Best	High	Low	Best	High
		(million barrels)
North Mine		760	930	1,160	114	140	174
South Mine		320	550	810	48	83	122
Total		1,080	1,480	1,970	162	223	296

35

Other Conventional Assets

        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 2006 daily production from these other conventional properties was approximately 43,225 BOE/d or approximately 50% of Enerplus' production. These other conventional reserves accounted for approximately 32% of Enerplus' estimated total Proved plus Probable Reserves as of December 31, 2006.

        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 ConocoPhillips Canada, 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 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. Operated conventional properties in southeast Saskatchewan include Tatagwa, Colgate, Heward and Neptune, as well as Routledge, Manitoba. Medium density oil production in these areas is generally pressure supported by natural water drive.

36

        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 invested approximately $175 million on development activities on its other conventional assets during 2006 to drill 275 gross (53.5 net) wells, of which 13 gross (11.9 net) wells were drilled in southeast Saskatchewan and 76 gross (6.0 net) wells were drilled on Enerplus' Deep Basin/Foothills properties. Enerplus currently plans to invest approximately $192 million on development activities on its other conventional properties in 2007. Major planned activities include investing approximately $36 million and drilling 88 gross (10 net) natural gas wells in the Deep Basin/Foothills area, investing approximately $38 million and drilling 29 gross (21.9 net) oil wells in southeast Saskatchewan and investing approximately $8 million and drilling 5 gross (5 net) oil wells at its Bantry North property.

Summary of Principal Production Locations

        During the year ended December 31, 2006, on a BOE basis, 74% of Enerplus' production was derived from Alberta, 13% from Montana, 8% from Saskatchewan, 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, 2006. All properties listed in the table (other than "Other") are located in Alberta unless otherwise noted.

2006 Average Daily Production

	Product
	Crude Oil
Property	Heavy	Light and Medium	NGLs	Natural Gas	Total
	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(BOE/d)
Sleeping Giant, Montana, U.S.A.	—	10,276	—	5,953	11,268
Bantry	3,052	—	80	29,940	8,122
Joarcam	—	2,062	89	5,926	3,139
Pembina 5 Way	—	2,116	141	1,928	2,578
Hanna Garden	—	4	4	12,689	2,123
Pine Creek	—	7	502	8,973	2,005
Verger	—	—	—	12,011	2,002
Chinchaga	—	—	—	11,890	1,982
Giltedge	1,893	—	—	143	1,917
Medicine Hat Glauconitic "C"	1,534	—	—	829	1,672
Elmworth	—	—	423	7,089	1,605
Benjamin	—	—	8	9,234	1,547
Shackleton, Saskatchewan	—	—	—	8,663	1,444
Valhalla	—	295	84	5,633	1,318
Progress	—	442	66	4,165	1,202
Medicine Hat South	—	—	—	7,124	1,187
Mitsue	—	823	129	1,153	1,144
South Wapiti	—	14	296	4,572	1,072
Enchant	—	375	28	3,901	1,053
Shorncliff	986	—	5	281	1,038
Virden, Manitoba	—	1,038	—	1	1,038
Other	1,439	9,778	2,628	128,874	35,323
TOTAL	8,904	27,230	4,483	270,972	85,779

37

Oil and Natural Gas Wells and Unproved Properties

        The following table summarizes, as at December 31, 2006, 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	3,267	1,275.4	6,201	3,080.6	983	347.0	561	195.1	775.3	271.5
Saskatchewan	2,355	452.8	837	452.1	296	31.9	13	5.7	204.4	124.0
British Columbia	202	24.2	143	30.6	39	4.7	62	15.6	164.2	73.9
Manitoba	558	310.8	—	—	14	7.9	—	—	56.2	52.5
Montana	174	92.1	—	—	1	0.5	—	—	73.9	43.7
North Dakota	2	1.5	—	—	—	—	—	—	90.9	70.1
Oil Sands (Alberta)	18	2.9	—	—	—	—	—	—	21.1	6.5
Total	6,576	2,159.7	7,181	3,563.3	1,333	392.0	636	216.4	1,386.0	642.2

Enerplus expects its rights to explore, develop and exploit on approximately 105,000 net acres of Unproved Properties to ordinarily expire prior to December 31, 2007. 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 generally allocates approximately 15% to 20% of its annual capital expenditures to longer-term opportunities in oil sands, land, seismic and higher risk drilling activities. 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 2006, Enerplus participated in the drilling of 790 gross oil and natural gas wells (360.8 net wells) with virtually a 100% net well success rate, plus 7 gross (0.1 net) service wells. The majority of Enerplus' drilling activity was in the shallow natural gas areas around Hanna Garden, Medicine Hat, Verger and Bantry. The Fund also had active operated drilling and facility programs in oil dominated areas such as Pembina, Joarcam, southeast Saskatchewan and Montana. The Shackleton shallow natural gas area in southwest Saskatchewan, the Joffre CBM area in Alberta, the Deep Basin area of northwestern Alberta and the Foothills region of western Alberta were the focus areas of non-operated drilling activity in 2006. 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, 2006, 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	157	55.7	5	1.8	41	26.5	—	—
Natural gas wells	506	252.2	69	22.8	—	—	—	—
Bitumen recovery well pairs	11	1.7	—	—	—	—	—	—
Service wells	7	0.1	—	—	—	—	—	—
Dry and abandoned wells	—	—	1	0.1	—	—	—	—
Total	681	309.7	75	24.7	41	26.5	0	0.0

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        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 (and subsequent development activities on such acquired properties) 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 2006 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 2006.

	Year Ended December 31, 2006
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Canada
Crude oil
Light and medium oil (bbls/d)		17,280		16,865		16,658		17,017		16,954
Heavy oil (bbls/d)		9,059		9,047		8,630		8,886		8,904
Total crude oil (bbls/d)		26,339		25,912		25,288		25,903		25,858
Natural gas liquids (bbls/d)		4,411		4,856		4,199		4,467		4,483
Total liquids (bbls/d)		30,750		30,768		29,487		30,370		30,341
Natural gas (Mcf/d)		265,354		263,265		260,381		271,061		265,019
Total Canada (BOE/d)		74,976		74,645		72,884		75,547		74,511
United States
Light and medium crude oil (bbls/d)		9,514		10,476		10,664		10,436		10,276
Natural gas (Mcf/d)		5,411		5,823		5,911		6,654		5,953
Total United States (BOE/d)		10,416		11,447		11,649		11,545		11,268
Total Enerplus
Crude oil
Light and medium oil (bbls/d)		26,794		27,341		27,322		27,453		27,230
Heavy oil (bbls/d)		9,059		9,047		8,630		8,886		8,904
Total crude oil (bbls/d)		35,853		36,388		35,952		36,339		36,134
Natural gas liquids (bbls/d)		4,411		4,856		4,199		4,467		4,483
Total liquids (bbls/d)		40,264		41,244		40,151		40,806		40,617
Natural gas (Mcf/d)		270,765		269,088		266,292		277,715		270,972
Total Enerplus (BOE/d)		85,392		86,092		84,533		87,092		85,779

39

Quarterly Netback History

        The following tables set forth Enerplus' average netbacks received for each fiscal quarter in 2006 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 2006. 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, 2006
Light and Medium Crude Oil ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price(1)	$	58.76		$	72.23		$	70.93		$	57.09		$	64.69
Royalties		(9.39	)		(12.26	)		(10.46	)		(8.34	)		(10.10	)
Production costs(2)		(13.38	)		(15.30	)		(14.79	)		(14.82	)		(14.57	)
Netback	$	35.99		$	44.67		$	45.68		$	33.93		$	40.02
United States
Sales price(1)	$	64.93		$	72.50		$	74.00		$	59.85		$	67.93
Royalties(3)		(13.26	)		(14.60	)		(15.06	)		(12.63	)		(13.91	)
Production costs(2)		(1.80	)		(1.60	)		(1.96	)		(1.79	)		(1.79	)
Netback	$	49.87		$	56.30		$	56.98		$	45.43		$	52.23
Total Enerplus
Sales price(1)	$	60.95		$	72.34		$	72.13		$	58.14		$	65.91
Royalties(3)		(10.43	)		(12.81	)		(11.93	)		(9.65	)		(11.21	)
Production costs(2)		(9.33	)		(10.11	)		(9.85	)		(9.94	)		(9.81	)
Netback	$	41.19		$	49.42		$	50.35		$	38.55		$	44.89

	Year Ended December 31, 2006
Heavy Oil ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada/Total Enerplus
Sales price(1)	$	38.20		$	58.12		$	57.30		$	43.38		$	49.22
Royalties		(9.39	)		(12.26	)		(10.46	)		(8.34	)		(10.10	)
Production costs(2)		(9.71	)		(10.61	)		(14.82	)		(14.91	)		(12.49	)
Netback	$	19.10		$	35.25		$	32.02		$	20.13		$	26.63

	Year Ended December 31, 2006
Natural Gas Liquids ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada/Total Enerplus
Sales price(1)	$	50.57		$	52.33		$	54.63		$	46.15		$	50.90
Royalties		(12.97	)		(13.53	)		(14.48	)		(11.91	)		(13.21	)
Production costs(2)		—			—			—			—			—
Netback	$	37.60		$	38.80		$	40.15		$	34.24		$	37.69

40

	Year Ended December 31, 2006
Natural Gas ($ per Mcf)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price(1)	$	8.32		$	6.17		$	6.09		$	6.57		$	6.79
Royalties		(1.82	)		(1.31	)		(1.09	)		(1.19	)		(1.35	)
Production costs(2)		(1.16	)		(1.30	)		(0.97	)		(1.24	)		(1.17	)
Netback	$	5.34		$	3.56		$	4.03		$	4.14		$	4.27
United States
Sales price(1)	$	8.61		$	8.25		$	7.69		$	6.81		$	7.78
Royalties(3)		(1.67	)		(1.60	)		(1.49	)		(1.32	)		(1.51	)
Production costs(2)		—			—			—			—			—
Netback	$	6.94		$	6.65		$	6.20		$	5.49		$	6.27
Total Enerplus
Sales price(1)	$	8.33		$	6.22		$	6.13		$	6.58		$	6.81
Royalties(3)		(1.82	)		(1.31	)		(1.10	)		(1.19	)		(1.35	)
Production costs(2)		(1.14	)		(1.28	)		(0.95	)		(1.21	)		(1.14	)
Netback	$	5.37		$	3.63		$	4.08		$	4.18		$	4.32

	Year Ended December 31, 2006
Total ($ per BOE)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price(1)	$	50.67		$	48.58		$	47.91		$	44.29		$	47.84
Royalties		(10.17	)		(9.39	)		(8.25	)		(7.67	)		(8.86	)
Production costs(2)		(8.37	)		(9.34	)		(8.59	)		(9.55	)		(8.97	)
Netback	$	32.13		$	29.85		$	31.07		$	27.07		$	30.01
United States
Sales price(1)	$	63.78		$	70.55		$	71.64		$	58.02		$	66.06
Royalties(3)		(12.12	)		(13.36	)		(13.79	)		(11.42	)		(12.68	)
Production costs(2)		(1.80	)		(1.60	)		(1.96	)		(1.79	)		(1.79	)
Netback	$	49.86		$	55.59		$	55.89		$	44.81		$	51.59
Total Enerplus
Sales price(1)	$	52.27		$	51.50		$	51.18		$	46.11		$	50.23
Royalties(3)		(10.40	)		(9.92	)		(9.01	)		(8.16	)		(9.36	)
Production costs(2)		(7.57	)		(8.31	)		(7.68	)		(8.52	)		(8.02	)
Netback	$	34.30		$	33.27		$	34.49		$	29.43		$	32.85

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.

41

Abandonment and Reclamation Costs

        In connection with its operations, Enerplus will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. Enerplus budgets for and recognizes as a liability the estimated fair value of the future retirement obligations associated with its property, plant and equipment. 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 $437 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 $194 million on an undiscounted basis and $24 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 $40 million on an undiscounted basis and $35 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

Tax Horizon

Canada

        No cash Canadian income taxes have been paid by the Fund or its Canadian Operating Subsidiaries for the year ended December 31, 2006. Under Enerplus' current structure and current Canadian tax laws, 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, under current Canadian tax laws, no Canadian income taxes would currently be expected to be incurred by the Fund or its Canadian Operating Subsidiaries in the future. However, as described in further detail under "General Development of Enerplus Resources Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts", "Oil and Natural Gas Reserves — Overview of Reserves", and "Risk Factors — Risks Relating to Enerplus' Structure and Ownership of the Trust Units", the Canadian federal government has introduced the Income Trust Tax Proposals which, if enacted as legislation, would generally tax income trusts at the same effective tax rates as Canadian corporations. Should the proposed legislation become substantially enacted, the Fund's future income taxes disclosed in its financial statements may be adjusted to include temporary differences between the accounting and tax bases of the Fund's assets and liabilities. In addition, the reported estimated net present value of future net revenues from Enerplus' oil and natural gas reserves may be adjusted to include an estimate of such revenues on an "after-tax" basis to reflect the impact of the income trust tax.

United States

        A total of $18.2 million of U.S. income related cash taxes were incurred with respect to U.S. operations during the year ended December 31, 2006. 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 9 to the Fund's audited financial statements for the year ended December 31, 2006.

Costs Incurred

        In the financial year ended December 31, 2006, Enerplus made the following expenditures:

		PropertyAcquisition Costs
		Proved		Unproved		Exploration Costs		Development Costs
		($ in millions)
Canada	$	35.3	$	20.0	$	32.5	$	322.0
United States		16.0		0.2		1.2		115.3
Total	$	51.3	$	20.2	$	33.7	$	437.3

42

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 $65.91/bbl for its light and medium crude oil, $49.22/bbl for its heavy crude oil and $50.90/bbl for its NGLs for the year ended December 31, 2006, compared to $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. 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 shared equitably to all supply producers. In 2006, these aggregator 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 via three routes. 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 2006 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 43% compared to 55% in 2005. The average price received by Enerplus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2006 was $6.81/Mcf compared to $8.41/Mcf in the year ended December 31, 2005. Within its sales portfolio of aggregator, downstream and spot natural gas, Enerplus sold approximately 42% of its natural gas based on the daily AECO market, 42% based on the monthly AECO market and 16% against the day and month NYMEX indices.

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 market prices, which exposes Enerplus to the risks associated with commodity price fluctuations and foreign exchange rates. See "Risk Factors". Information regarding Enerplus' financial instruments is contained in Note 10 to the Fund's audited annual consolidated financial statements for the year ended December 31, 2006 and under the headings "Pricing" and "Price Risk Management" in the Fund's management's discussion and analysis for the year ended December 31, 2006, each of which is available through the Internet on Enerplus' website at www.enerplus.com, on Enerplus' SEDAR profile at www.sedar.com and on EDGAR at www.sec.gov.

Environment, Health and Safety

        Enerplus places a high priority on preserving the quality of its environment and protecting the health and safety of its employees, contractors and the public in the communities in which it lives and works. Enerplus actively participates in industry-recognized programs at the highest possible levels in an effort to support continuous improvement.

43

        In 2006, Enerplus again received the Certificate of Recognition as part of the Partnership Program with Alberta Human Resources and the Workers' Compensation Board. This certificate is given to employers who develop health and safety management systems that meet established standards. Enerplus has maintained its Certificate of Recognition through annual reviews and audits every three years since 2000. The second independent audit of Enerplus' environment, health and safety ("EHS") management system was conducted in 2006 and Enerplus received a 95% score.

        Enerplus' actual safety performance declined in 2006 as compared to 2005. A total of eight employee recordable injury incidents were recorded in 2006, resulting in a lost time injury frequency rate of 0.53 per 200,000 man hours compared to 0 incidents per 200,000 man hours in 2005. In addition, Enerplus' contractor lost-time injury frequency also increased from 0.46 per 200,000 man hours in 2005 to a rate of 0.97 per 200,000 man hours in 2005. While the majority of these incidents were of a lesser severity, Enerplus is nevertheless concerned about the higher level of incidents. Enerplus is working to improve its safety performance through increased awareness in the field, personalizing safety messages so they have a more profound impact on personal decisions, and increasing the accountability for safety throughout the organization.

        Enerplus is committed to meeting its responsibilities to protect the environment through a variety of programs and actively monitoring its compliance with all regulators. In particular, Enerplus engages in the following activities:

•   Enerplus participated in the Environment, Health and Safety Stewardship Program developed by the Canadian Association of Petroleum Producers at the highest level, platinum. Enerplus' participation requires its commitment to continuous improvement in its EHS management practices including sound planning and implementation, open communication and demonstrated performance and a thorough external audit of its activities at least once every five years;

•   Enerplus increased its spending on reclamation and site abandonment by approximately 48% to $6.1 million. Site abandonment and reclamation occurs when areas are returned to their original state once operations have been completed. Enerplus' reclamation activities resulted in 36 reclamation certificates being received with another 58 sites ready for review by Alberta Environment. This correlates to a 13% reduction in Enerplus' total reclamation sites from 2005;

•   Enerplus doubled its remediation spending in 2006 to $9.6 million and reduced its reportable spills by 18%. Remediation is the environmental clean-up of spills or issues, many of which are associated with older properties or changing regulations;

•   Enerplus enhanced its pipeline integrity efforts and reduced pipeline failures by 13% year-over-year through its Pipeline Management Program and related activities. The Pipeline Management Program is designed to maintain the integrity of Enerplus' underground pipelines through on-going risk assessment. In 2006, 90% of Enerplus' 6,000 kilometres of pipeline were assessed with appropriate actions taken to identify future pipeline leaks or breaks; and

•   Enerplus increased the number of internal emergency response drills to prepare its staff in the case of an emergency.

 In 2007, Enerplus intends to spend approximately $16 million on EHS activities and particularly focus on, among other things, the following EHS activities and initiatives:

•   maintaining spending levels on abandonment and restoration activities;

•   working to improve its safety performance through awareness in the field, personalizing safety messages to have a stronger impact on personal decisions and increasing the accountability throughout the organization for safety;

•   evaluating Enerplus' impact on the environment. With growing concern over global warming and environmental matters, Enerplus is looking at additional ways it can minimize its environmental impact;

•   evaluating and implementing options to increase safety presence and ownership of Enerplus' safety programs at the field level; and

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• expanding its efforts relating to employee and contractor safety compliance through enhanced safety orientations, awareness and training sessions.

        Overall, Enerplus believes its EHS initiatives confirm its ongoing commitment to environmental stewardship and the health and safety of its employees, contractors and the general public in the communities in which it operates.

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 "— Environment, Health and Safety" above. 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 2006. 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, liability coverage is also carried for directors and officers of Enerplus.

Personnel

        As at December 31, 2006, Enerplus employed a total of 606 persons.

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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. A copy of the Trust Indenture was filed on the Fund's SEDAR profile at www.sedar.com on January 5, 2004 and on EDGAR at www.sec.gov on December 7, 2006.

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 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

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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

47

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

48

non-residents exceeds a 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" 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 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 to Unitholders

        The Fund makes distributions to unitholders from the cash payments that it receives, directly or indirectly, from its Operating Subsidiaries. It receives income from EnerMark, ERC and Enerplus Oil & Gas pursuant to the royalty agreements, as well as from dividend and distribution payments received, directly or indirectly, 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 cash distributions that are to be paid to the Fund's unitholders 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 cash distributions, if any, that will be paid 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 "net income" and "net realized capital gains" of the Fund (as defined in the Trust Indenture and not as calculated in accordance with GAAP), together with such other amounts as EnerMark may determine, for that period ending on the distribution record date to the extent those amounts were not previously declared payable. The authority to determine the amount of cash

49

distributions, 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 (generally 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 cash that is determined to be necessary to pay any tax liability of the Fund, and those amounts will not be payable as distributions 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

50

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.

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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 EnerMark's Subordinated Notes

        The Fund's primary sources of cash are 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 and dividend and distribution payments received by the Fund from certain of its subsidiaries. Additionally, EnerMark makes interest and principal payments on unsecured, subordinated debt to another subsidiary of the Fund which subsequently pays distributions to the Fund. Outlined below is a

52

description of the royalties granted by EnerMark, ERC and Enerplus Oil & Gas to the Fund and the subordinated debt issued by EnerMark to another subsidiary of 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 income from their respective oil and natural gas properties and operations. The royalties are paid to the Fund 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 another subsidiary of the Fund, which subsequently pays distributions 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, directly or indirectly, from the Fund or its subsidiaries 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 and the Fund's subsidiary which directly holds the EnerMark notes have each entered into a subordination agreement pursuant to which the payment by EnerMark of obligations under the subordinated notes 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 Subsidiaries of the Fund

        As stated above, the terms of the existing royalty agreements and the subordinated debt issued by EnerMark, together with the subordination agreements entered into by the Fund and the Fund's subsidiary that directly holds the subordinated notes and the terms of EnerMark's credit facilities and senior notes, result in the royalty, interest, distribution and dividend payments made directly or indirectly from the Fund's 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 made directly or indirectly from EnerMark, ERC,

53

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 2006 Annual Report and under the heading "Statement of Corporate Governance Practices" in the Fund's information circular and proxy statement dated March 12, 2007. 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 indirect 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 was filed as a "Security holder document" on April 12, 2005 on the Fund's SEDAR profile at www.sedar.com, was filed on EDGAR at www.sec.gov on February 6, 2007, and is available on the Fund's website at www.enerplus.com under "Governance".

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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 third party indebtedness of Enerplus is incurred directly by its primary Operating Subsidiary, EnerMark. As at December 31, 2006, 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 credit agreement with nine North American banks that currently is scheduled to mature in November 2009, subject to further extension by the lenders. As at December 31, 2006, $348.5 million was outstanding under this facility. This bank debt carries floating interest rates that Enerplus expects to range between 55.0 and 110.0 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;
	•  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).

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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 installments 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" and "Consolidated EBITDA" have the same meanings as "Consolidated Senior Debt" and "Consolidated EBITDA", respectively, in the definitions relating to the Bank Credit Facility.

        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 7 to the Fund's audited annual consolidated financial statements for the year ended December 31, 2006 and under the heading "Liquidity and Capital Resources — Long-Term Debt" in Enerplus' management's discussion and analysis for the year ended December 31, 2006. 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 EnerMark's Subordinated Notes" and "Risk Factors".

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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.

Cash Distributions

        The Fund may, on or before any distribution record date, declare cash distributions payable to the unitholders. See "Information Respecting Enerplus Resources Fund — Description of the Trust Units and the Trust Indenture — Distributions to Unitholders".

        Although the Fund intends to make monthly cash distributions to its 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, directly or indirectly, 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 distributions paid by the Fund to unitholders is dependent on the amount of cash flow paid to the Fund by its Operating Subsidiaries and can vary significantly from period to period for a number of reasons, including among other things (i) the Operating Subsidiaries' operational and financial performance (including fluctuations in the quantity of Enerplus' oil, NGLs and natural gas production and the sales price that Enerplus realizes for such production (after hedging contract receipts and payments)), (ii) fluctuations in the costs to produce oil, NGLs and natural gas and to administer and manage the Fund and its subsidiaries, (iii) the amount of cash required or retained for debt service or repayment, (iv) amounts required to fund capital expenditures and working capital requirements, and (v) foreign currency exchange rates and interest rates. Certain of these 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 addition, the level of distributions per Trust Unit will be affected by the number of outstanding Trust Units. In the past, the level of cash retained has historically varied between 10% and 40% of Enerplus' total annual cash flow from operating activities. For the year ended December 31, 2006, approximately 29% of the cash flow from operating activities was retained, resulting in a "payout ratio" of 71%.

        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".

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Distribution History

        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	2007	2006		2005		2004		2003
January(1)	$0.42	$	0.42	$	0.35	$	0.35	$	0.30
February	0.42		0.42		0.35		0.35		0.32
March	0.42		0.42		0.35		0.35		0.35
April	N/A		0.42		0.35		0.35		0.35
May	N/A		0.42		0.35		0.35		0.37
June	N/A		0.42		0.35		0.35		0.37
July	N/A		0.42		0.35		0.35		0.37
August	N/A		0.42		0.37		0.35		0.37
September	N/A		0.42		0.37		0.35		0.37
October	N/A		0.42		0.37		0.35		0.37
November	N/A		0.42		0.42		0.35		0.35
December	N/A		0.42		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".

Canadian Tax Reporting Matters

        The Fund currently qualifies as a mutual fund trust under the Canadian Tax Act and each year the Fund has historically transferred all of its taxable income to unitholders by way of distributions. For Canadian tax purposes, approximately 4% of the Fund's 2006 distributions was a tax-deferred return of capital, approximately 95% was taxable to unitholders as other income and less than 1% was taxable eligible dividend income. See "Risk Factors — Risks Relating to Enerplus' Structure and the Ownership of the Trust Units".

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, approximately 90% of the distributions paid by the Fund during 2006 were 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' 2006 distributions should be considered "Qualified Dividends" eligible for a reduced 15% rate of tax applicable to long term capital gains. This 15% tax rate is currently scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate for "Qualified Dividends" will be renewed by the U.S. government at such time. See "Risk Factors — Risks Related to Enerplus' Structure and the Ownership of the Trust Units" and "Risk Factors — Risks Particular to United States and Other Non-Resident Unitholders".

        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.

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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 approximately 74% of Enerplus' 2006 average daily production occurred). Enerplus also owns oil and natural gas properties and related assets in Montana, North Dakota and Wyoming 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, resulting in a market price for 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

59

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 in the Canadian provinces where Enerplus operates 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.

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        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 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.

        The current Alberta royalty system for oil sands is scheduled to expire on June 30, 2007. The Government of Alberta has stated that it intends to conduct a thorough review and analysis of the current royalty regime in place in Alberta and in particular the royalty system applicable to the oil sands, with the panel appointed to review the oil sands royalty system expected to submit a final report with recommendations to the government by August 31, 2007. As a result, the government is expected to extend the existing oil sands royalty system until June 30, 2008. See "Risk Factors — Risks Related to Enerplus' Business and Operations".

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

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(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, and the Canadian federal government is currently evaluating other proposals and legislative measures that would achieve similar objectives. The upstream Canadian oil and gas sector is in discussions with various federal and provincial levels of government regarding the development of greenhouse 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 emissions and set 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.

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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. Unitholders and 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.

In particular, Enerplus directs unitholders and prospective investors to the description of the risks under the heading "Risk Factors — Risks Related to Enerplus' Structure and the Ownership of the Trust Units — Changes in tax and other laws may adversely affect unitholders" as the Income Trust Tax Proposals could potentially have a significant impact on Enerplus' business, operations and financial condition, as well as the value of the Trust Units to unitholders.

Risks Related to Enerplus' Business and Operations

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

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

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

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

• currency fluctuations;

• global and domestic economic conditions;

• weather conditions;

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

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

• the level of consumer demand;

• the price and availability of alternative fuels;

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

• the availability of refining capacity;

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

• government regulations.

         Any decline in crude oil or natural gas prices may have a material adverse effect on Enerplus' operations, financial condition, borrowing ability, levels of reserves and resources and the level of expenditures for the development of Enerplus' oil and natural gas reserves or resources. 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

63

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, energy services 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, develop or expand its oil and gas reserves and resources 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 cash distributions may 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 Subsidiaries 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 U.S. Operating Subsidiaries or other direct or indirect subsidiaries of the Fund. 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 cash distributions 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 (including income tax laws and environmental laws) and other factors beyond the control of the Fund. In addition, the market value of the

64

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. Furthermore, Enerplus conducts certain of its business and operations in the United States and as a result it also incurs certain expenses in United States dollars and is therefore exposed to foreign currency risk to the extent the value of the Canadian dollar decreases relative to the United States dollar. 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 7(b) to the Fund's audited consolidated financial statements for the year ended December 31, 2006.

If Enerplus is unable to add or develop additional reserves or its resources, 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 of reserves and resources, together with certain exploration activities. As a result, the level of Enerplus' future oil and natural gas reserves are highly dependent on its success in developing and exploiting its reserve and resource base and acquiring additional reserves and/or resources. 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 or resource 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 and to develop its resources will be impaired. Even if the necessary capital is available, Enerplus cannot assure prospective investors that it will be successful in acquiring additional reserves or resources on terms that meet its investment objectives. Without these 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 distributions to the Fund's unitholders.

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

        The value of the Trust Units depends upon, among other things, the reserves and resources attributable to Enerplus' properties. Estimates of reserves and resources are by necessity projections, and thus are inherently uncertain. The process of estimating reserves or resources requires interpretations and judgements on the part of petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Different engineers may make different estimates of reserve or resource quantities and revenues attributable thereto based on the same data. Ultimately, actual reserves and resources attributable to Enerplus' properties will vary and be revised from current estimates, and those variations and revisions may be material. The reserve and resource 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 and resources. These factors and assumptions include, among others:

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

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

• initial production rates;

• production decline rates;

• ultimate recovery of reserves and resources;

65

• success of future exploitation activities;

• marketability of production;

• effects of government regulation; and

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

        Reserve and resource 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 and resources could vary materially from its estimates. Additionally, all such estimates are, to some degree, uncertain and classifications of reserves and resources 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 and resources 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 and resources that may be developed and produced in the future (particularly oil sands reserves and resources) are often based upon volumetric or probabilistic calculations and upon analogy to similar types of reserves or resources, 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 or resources based upon production history may result in variations or revisions in the estimated reserves or resources, and any such variations or revisions could be material.

        Reserve and resource 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 reserves or 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. Additionally, if current development plans for the Joslyn Project are modified (and in particular with respect to SAGD Phase III, in respect of which Enerplus has booked certain Probable Reserves) and a decision is made to mine certain portions of the SAGD-designated part of the Joslyn Project, the volume and estimated value of the Probable Reserves assigned to Phase III of the SAGD portion of the Joslyn Project could be negatively impacted. Although mining typically provides approximately twice the recovery of bitumen in place as compared to SAGD projects, there could be timing differences between reserves bookings associated with the existing Phase III development plans versus possible expansion of mine development plans.

        In addition, references to "contingent resources" or "resources" in this Annual Information Form do not constitute, and should be distinguished from, references to "reserves". "Reserves" are those remaining quantities of oil and gas anticipated to be economically recoverable from these known accumulations from a given date forward. "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally accumulations but are not capable of being classified as "reserves", and "contingent resources" are a sub-category of resources that means those quantities of oil and gas estimated to be potentially recoverable from known accumulations but which cannot be classified as "reserves" for a variety of reasons, including that they may not be currently economic. See "Presentation of Enerplus' Oil and Natural Gas Reserves, Resources and Production Information".

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 Total and Enerplus have conducted 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.

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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 36% 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. This places greater reliance on third party operators in making estimates of future capital expenditures.

        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 Total, and accordingly the future success of that Project is highly dependent on the strategies, operations and management of Total. The Joslyn Project is also subject to the risk that Total 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 may be subject to the risk of default by Total in meeting its obligations to pay its proportionate share of expenditures of the Joslyn Project. Such default by Total 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

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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:

• breakdown or failure of equipment or processes;

• construction performance falling below expected levels of output or efficiency;

• design errors;

• contractor or operator errors;

• 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;

• labour disputes, disruptions or declines in productivity;

• increases in materials or labour costs;

• inability to attract sufficient numbers of qualified workers;

• delays in obtaining, or conditions imposed by, regulatory approvals (including, without limitation, with respect to Phase III of the SAGD project and future mining operations);

• changes in Project scope;

• violation of permit requirements;

• disruption in the supply of energy;

• availability of drilling rigs and services;

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

• reliance on technologies that have not yet been demonstrated to be commercially applicable in oil sands applications.

        Given the stage of development of the Joslyn Project, various changes to the Project may be made by Total 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, resource 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.

        At the current time, there are no announced plans for construction of an upgrader to upgrade the quality of the Joslyn Bitumen produced by the Joslyn Project. As a result, there are a number of risks involved in transporting and marketing the Joslyn Bitumen, including securing supplies of condensate or synthetic light oil to blend with the bitumen in order to move it to market economically and, as there are fewer markets for non-upgraded bitumen, those markets typically demand a price discount relative to lighter crude oil.

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 and/or resources, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other

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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.

        Furthermore, if the Income Trust Tax Proposals are implemented as proposed, Enerplus would effectively be taxed at a level similar to Canadian corporations starting in 2011 (assuming Enerplus does not violate the "normal growth" safe harbour provisions). Therefore, Enerplus' proposed bids for Canadian corporate and property acquisitions may be affected and adjusted for the impact of the Income Trust Tax Proposals, and Enerplus may not have the same access to capital with respect to corporate and property acquisitions which it has previously experienced. The Income Trust Tax Proposals may put Enerplus at a competitive disadvantage to other industry participants such as pension resource corporations, U.S. flow-through entities such as master limited partnerships and limited liability companies, and U.S. corporations that are able to minimize Canadian tax through the use of inter-company debt and cross-border tax planning measures.

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 in Canada and federal and state laws and regulations in the United States. 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, and the Canadian federal government is currently evaluating other proposals and legislative measures that would achieve similar environmental objectives. Although the outcome of this process is unknown at this time, the implementation of more stringent environmental legislation or regulatory requirements 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".

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        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. The Government of Alberta has stated that it intends to conduct a thorough review and analysis of the current royalty regime in place in Alberta and in particular the royalty system applicable to the oil sands. See "Industry Conditions — Royalties and Incentives".

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 and resources 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 of 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 distributions 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

70

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 and resources, the management and administration of all matters relating to Enerplus' properties and the administration of the Fund. The rapid increase in oil and gas prices and activity in recent years, 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. See "Directors and Officers — Trust Unit Ownership and Conflict of Interest". 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. Under U.S. GAAP, the carrying value of these properties and facilities, net of deferred income taxes, is limited to the present value of after-tax future net revenue from Proved Reserves, discounted at 10%, and based on constant prices at December 31, 2006. If the net capitalized costs exceed either of these limits, Enerplus must charge the amount of the excess against its Canadian or U.S. GAAP earnings, respectively. Additionally, if oil and natural gas prices decline, Enerplus' net capitalized cost may exceed these limits, 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 and resources.

        From time to time, Enerplus conducts title reviews in accordance with industry practice prior to purchases of 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 (and, if applicable, resources) from the purchased assets could be jeopardized and, as a result, distributions to unitholders may be reduced. Furthermore, from time to time, Enerplus may have disputes with industry partners as to ownership rights of certain properties or resources, including disputes as to the rights of holders of coal rights versus the rights of holders of natural gas rights with respect to coalbed methane properties.

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 or the taxation of the Fund's distributions to unitholders, 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

71

changed or interpreted in a manner which is detrimental to Enerplus' operations and financial structure, and therefore the unitholders.

Proposed Taxation of Income Trusts

        As described above under "General Development of Enerplus Resources Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts", on October 31, 2006, the Canadian federal government announced the Income Trust Tax Proposals to generally tax income trusts at the same effective tax rates as Canadian corporations, and draft legislation to implement these proposals was released in December 2006. At this time, the draft legislation to give effect to the Income Trust Tax Proposals has not yet been introduced into the Canadian House of Commons and therefore has not been approved or declared in force by the Canadian government. Accordingly, Enerplus is unable to determine the timing of when the proposed legislation could be passed in the Canadian Parliament, if at all, and it is uncertain as to what form, if any, changes in Canadian income tax laws will take as a result of such proposal. If implemented in their current or an alternative form, the Income Trust Tax Proposals could have a significant effect on the Fund's business, operations and financial conditions, including, among other things:

• the Fund may be required to pay taxes, or higher amounts of taxes, in the future or in years earlier than it would under existing tax laws, which could decrease the amount of cash distributions available to unitholders;

• the ongoing structure of the Fund and its subsidiaries, including whether the Fund and its subsidiaries will continue to operate under the income trust model or convert to another model, including a corporate form, and the tax implications to the Fund, its subsidiaries and its unitholders as a result of any change on the Fund's structure;

• the ability of the Fund to pay monthly cash distributions and the amount of such distributions could be adversely affected;

• the estimated net present value of future net revenues from Enerplus' oil, NGLs and natural gas reserves may be decreased as a result of the application of taxes to which Enerplus has historically not been subject (see "Oil and Natural Gas Reserves — Overview of Reserves" and "Operational Information — Tax Horizon");

• future income tax liability in the Fund's consolidated financial statements will increase to reflect temporary timing differences between the accounting and tax bases of the Fund's assets and liabilities, which Enerplus understands would likely be reflected as a non-cash charge to the Fund's consolidated statement of income, and the amount of such charge could be material;

• at the current time, Enerplus does not expect the proposed tax on income trusts to have a material impact on its debt covenants;

• the Fund's ability to raise capital may be restricted due to the market's reaction to the proposed tax, the related changes to the Fund's accounting and reserves, and the ongoing uncertainty concerning the Fund's future structure and business strategy; and

• the trading price and liquidity of the Trust Units may be adversely affected.

        Furthermore, the "normal growth" safe harbour guidance announced by the Canadian federal government on December 15, 2006 are administrative in nature and are not law and therefore can be revised without an Act of the Canadian Parliament. See "General Development of Enerplus Resources Fund — Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts". Therefore, no assurance can be provided that such safe harbour provisions will remain in effect in the current form or that the Fund will not be subject to the proposed tax on income trusts (if any) prior to 2011.

Mutual Fund Trust Status

        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

72

recent information obtained by Enerplus through its transfer agent and financial intermediaries, in January 2007 an estimated 70% 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 has determined that it currently meets the requirements 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.

        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 of 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, as it currently exists. 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".

        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".

Other Potential Legislative Changes

        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 Developments in the Past Three Years — Federal Government Pronouncements on Income Trusts". 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.

73

• 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 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 material 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 as the Fund is not a legally recognized entity within the definitions of statutes such as the Bankruptcy and Insolvency Act (Canada) or the Companies' Creditors Arrangement Act (Canada). 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 not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, the Fund is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company. In addition, although the Fund qualified at Closing as a "mutual fund trust" as defined by the Tax Act, the Fund is not a "mutual fund" as defined by applicable securities legislation.

        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 or resources 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 or resources 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

74

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.

        United States unitholders (meaning, for the purposes of this section, tax residents for United States federal income tax purposes as defined under Section 7701 of the United States Internal Revenue Code, as amended (the"Code")) should be aware that the United States Internal Revenue Service may determine that the Fund is a "passive foreign investment company" (a "PFIC") under Section 1297(a) of the Code for the 2006 taxable year and in subsequent taxable years. The Fund will be a PFIC if at least 75 percent of its income consists of dividends, interest, and other passive items or if 50 percent or more of the average value of its assets (on a gross value basis) consist of assets that would produce passive income. To date, Enerplus has received advice that the Fund should not be considered a PFIC for the years 2002 through 2005, and Enerplus does not expect to be considered a PFIC for 2006 or 2007.

        If the Fund is or becomes a PFIC, adverse United States federal income tax consequences may apply. Any gain recognized on the sale of Trust Units and any excess distributions (as defined under Section 1291(b) of the Code) paid on the Trust Units must be ratably allocated to each day in a United States unitholder's holding period for the Trust Units. The amount of any such gain or excess distribution allocated to prior years of such United States unitholder's holding period for the Trust Units generally will be subject to United States federal income tax at the highest tax rate applicable to ordinary income in each such prior year, and the United States unitholder will be required to pay interest on the resulting tax liability for each such prior year, calculated as if such tax liability had been due in each such prior year.

Alternatively, a United States unitholder that makes a "qualified electing fund" election generally will be subject to United States federal income tax on such United States unitholder's pro rata share of the Fund's "net capital gain" and "ordinary earnings" (calculated under United States federal income tax rules), regardless of whether such amounts are actually distributed by the Fund. United States unitholders should be aware that there can be no assurance that the Fund will satisfy record keeping requirements or that it will supply United States unitholders with required information under the "qualified electing fund" rules, in the event that the Fund is a PFIC and a United States unitholder wishes to make a "qualified electing fund" election. As a second alternative, a United States unitholder may make a "mark-to-market election" if the Fund is a PFIC and the Trust Units are marketable stock regularly traded on a securities exchange or other market the United States Secretary of the Treasury determines as adequate. A retroactive election is permitted only in accordance with the United States Treasury Regulations and in some circumstances will require the permission of the United States Commissioner of the Internal Revenue Service. Additionally, United States holders will not be able to make the "mark-to-market" election with respect to the Fund's Operating Subsidiaries should they be determined to be PFICs. A United States unitholder that makes a "mark-to-market election" generally will include in gross income, for each taxable year in which the Fund is a PFIC, an amount equal to the excess, if any, of (a) the fair market value of the Trust Units as of the close of such taxable year over (b) such United States unitholder's tax basis in such Trust Units. United States unitholders are strongly urged to consult their own tax advisors regarding the United States federal income tax consequences of the Fund's possible classification as a PFIC and the consequences of such classification. 

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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. Since January 1, 2005, a 15% Canadian withholding tax is applied to return of capital portion of distributions made to non-resident unitholders. See "Distributions to Unitholders — U.S. Tax Reporting Matters".

        Additionally, the reduced "Qualified Dividend" rate of 15% tax applied to the Fund's distributions under current U.S. tax laws is scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate will be renewed by the U.S. government at such time.

        Furthermore, it is unclear what impact the proposed changes to the Tax Act relating to the Income Trust Tax Proposals will have on the taxation of cash distributions or other property paid by the Fund to unitholders who are not residents of Canada. See "Risk Factors — Risks Released to Enerplus' Structure and Ownership of the Trust Units — Changes in tax and other laws may adversely affect unitholders".

Non-resident unitholders are subject to foreign exchange risk on the distributions that they may receive from the Fund.

        The Fund's distributions are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar weakens with respect to their currency, the amount of the distribution will be reduced when converted to their home currency.

The ability of United States and other non-resident unitholder 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 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 and resource 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.

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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 2006.

Month	High		Low		Close		Volume
January	$	61.06	$	55.59	$	60.60		3,727,732
February		64.36		52.12		57.67		6,456,504
March		59.20		56.00		58.57		6,486,261
April		60.56		58.30		59.91		3,594,863
May		62.00		53.55		62.00		8,581,020
June		63.87		54.00		63.00		7,609,973
July		65.44		60.00		65.06		5,335,279
August		66.00		62.35		64.25		4,770,115
September		64.90		50.69		56.10		8,328,428
October		62.22		51.60		60.81		7,729,517
November		54.70		43.86		52.50		15,136,661
December		54.18		49.79		50.68		4,363,809

 The following table sets forth certain trading information for the Trust Units on the NYSE in 2006.

Month	High		Low		Close		Volume
January		US$53.44		US$47.95		US$53.08		5,185,400
February		56.05		45.10		50.67		8,178,000
March		52.10		48.11		50.44		4,830,700
April		53.60		50.10		53.59		3,989,300
May		56.03		46.51		55.74		6,955,100
June		58.00		48.55		56.24		6,384,400
July		57.94		53.30		57.54		3,457,500
August		59.45		55.55		58.29		3,875,400
September		58.73		45.41		50.29		9,360,700
October		55.44		45.69		54.30		5,835,000
November		48.42		38.50		46.13		18,847,900
December		46.75		42.76		43.61		4,777,800

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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 V. Dodge(3)(4)(6) Vancouver, British Columbia, Canada	May 2004	Corporate director since 2004. Prior thereto, Chief Operating Officer of Canadian Pacific Railway Limited (a public Canadian national rail company).
Gordon J. Kerr(10) Calgary, Alberta, Canada	May 2001	President and Chief Executive Officer of Enerplus.
Douglas R. Martin(1)(7) Calgary, Alberta, Canada	September 2000	President of Charles Avenue Capital Corp. (a private merchant banking company).
Robert L. Normand(2)(4)(8) Rosemere, Québec, Canada	March 1998	Corporate director.
Glen D. Roane(2)(4) Canmore, Alberta, Canada	June 2004	Corporate director.
W.C. (Mike) Seth(3)(5) Calgary, Alberta, Canada	August 2005	President of Seth Consultants Ltd. (a private consulting firm) since June 2006. From July 2005 to June 2006, Mr. Seth was Chairman of McDaniel & Associates Consultants Ltd. ("McDaniel") (a petroleum engineering consulting firm). 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 & Risk Management Committee is comprised of Robert L. Normand as Chairman, Harry B. Wheeler and Glen D. Roane.

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

(4) The Compensation & Human Resources Committee is comprised of Glen D. Roane as Chairman, Robert L. Normand and Edwin V. 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 & Safety Committee is comprised of Donald T. West as Chairman, Edwin V. 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

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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)  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.

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 & Chief Executive Officer	President & Chief Executive Officer of Enerplus.
Garry A. Tanner Calgary, Alberta, Canada	Executive Vice President & Chief Operating Officer	Executive Vice President & Chief Operating Officer of Enerplus since April 2006. Prior thereto, Senior Vice President & Chief Operating Officer of Enerplus since February 2003. Prior thereto, Senior Vice President, New Business Development of EGEM and Senior Vice President of El Paso Merchant Energy (a merchant trading company).
Ian C. Dundas Calgary, Alberta, Canada	Senior Vice President, Business Development	Senior Vice President, Business Development since August 2004. Prior thereto, Vice President and Director, Business Development of Enerplus since January 2003. Prior thereto, Vice President of EGEM.
Robert J. Waters Calgary, Alberta, Canada	Senior Vice President & Chief Financial Officer	Senior Vice President & Chief Financial Officer of Enerplus.
Jo-Anne M. Caza Calgary, Alberta, Canada	Vice President, Investor Relations	Vice President, Investor Relations of Enerplus.
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.
Larry P. 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).

79

Name and Residence	Office	Principal Occupation for Past Five Years(1)
Lyonel G. Kawa Calgary, Alberta, Canada	Vice President, Information Services	Vice President, Information Services since January 2007. Prior thereto, Manager, Information Systems and Technology with Burlington Resources Canada Ltd. (an oil and gas exploration and production company) since July 2004. Prior thereto, Team Leader with TransCanada Pipelines Ltd. (a public energy transportation and infrastructure company).
Jennifer F. Koury Calgary, Alberta, Canada	Vice President, Corporate Services	Vice President, Corporate Services of Enerplus since October 2006. Prior thereto, a private consultant.
Eric G. Le Dain Calgary, Alberta, Canada	Vice President, Marketing	Vice President, Marketing of Enerplus since September 2006. Prior thereto, Executive Director of Energy Marketing of UBS Commodities Canada Ltd. (a financial services 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 Crossfield, 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.
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.

80

Trust Units Ownership

        As of March 8, 2007, the directors and officers named above beneficially own, directly or indirectly, an aggregate of 438,657 Trust Units, representing approximately 0.4% of the outstanding Trust Units as of that date.

Conflicts of Interest

        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. In situations where conflicts of interest arise, Enerplus expects the applicable director or officer to declare the conflict and, if a director of EnerMark, abstain from voting in respect of such matters on behalf of Enerplus.

        Enerplus currently has equity investments in the some of the same companies as EnCap Investments L.P. ("EnCap"), of which Mr. Robert L. Zorich (a director of EnerMark) is a principal and the Managing Director. In the future, Enerplus may invest alongside EnCap on similar equity investments. In some circumstances, EnCap may have established its equity position at an earlier time and at a lower value than has Enerplus and may have differing investment and timing objectives relating to those investments as compared to Enerplus. In the future, Enerplus may also make offers to acquire companies where EnCap is an investor. Additionally, Mr. Glen D. Roane, a director of EnerMark, is Chair of a private energy services company that supplies products and services to Enerplus, and Mr. W.C. (Mike) Seth, a director of EnerMark, owns 50% of a private software company that provides software services to Enerplus.. Enerplus does not consider the level of products and services supplied by such companies to be material to Enerplus.

        See "Risk Factors — Potential Conflicts of Interest".

Audit & Risk Management Committee Disclosure

        The disclosure regarding Enerplus' Audit & Risk Management 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, 2004 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 filed on the Fund's SEDAR profile at www.sedar.com on January 5, 2004 and was filed on EDGAR at www.sec.gov on December 7, 2006. A copy of the Fund's Unitholder Rights Plan Agreement, which is described under "Information Respecting Enerplus Resources Fund — Unitholder Rights Plan", was filed on the Fund's SEDAR profile at www.sedar.com on April 12, 2005 and was filed on EDGAR at www.sec.gov on February 6, 2007, and is available on the Fund's website at www.enerplus.com under "Governance".

81

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 both the GLJ Reserves Report in respect of the SAGD reserves and the GLJ Joslyn Resources Report in respect of the contingent bitumen resources attributable to Enerplus' working interest in the Joslyn Project, a summary of which is contained in this Annual Information Form. As of the dates of each of the GLJ Reserves Report and the GLJ Joslyn Resources 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, Independent Registered Chartered Accountants, Calgary, Alberta. Deloitte & Touche LLP has confirmed that it is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta, the Securities Acts administered by the Securities and Exchange Commission and the requirements of the Independence Standards Board.

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, on the EDGAR website at www.sec.gov and on the Fund's website at www.enerplus.com. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Fund's securities and securities authorized for issuance under equity compensation plans, as applicable, is contained in the Fund's information circular dated March 12, 2007 for its 2007 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, 2006. Unitholders who wish to receive printed copies of these documents free of charge should contact the Fund's Investor Relations department using the contact information included on the final page of this Annual Information Form.

82

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 the Company's Reserves Data as at December 31, 2006. The Reserves Data consist of the following: 

  (a) (i)     proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 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, 2006 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).

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

4. The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us as of December 31, 2006, 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 P&NG Reserves in Canada of Enerplus Resources Fund, as of December 31, 2006, prepared July 2006 to February 2007	Canada	Nil	$	4,103.6	$	433.1	$	4,536.7

5. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented 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	/s/  ROBERT R. WARHOLM
Calgary, Alberta, Canada February 12, 2007	Robert R. Warholm , P. Eng. Associate
	/s/  MICHAEL W. MAUGHAN
	Michael W. Maughan, C.P.G., P. Geol. Vice President, Geoscience
	/s/  R. KEITH MACLEOD
	R. Keith MacLeod, P. Eng. Executive Vice-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 EnerMark Inc. (the "Company"):

1.We have prepared an evaluation of the Company's reserves data as at December 31, 2006. The reserves data consist of the following:

  (a) (i)     proved and proved plus probable oil and gas reserves estimated as at December 31, 2006, 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, 2006, 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).

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

4.     The following table sets forth the estimated future net revenue (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, 2006, 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 7, 2007	Canada	—	$	47,978	—	$	47,978

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
January 29, 2007 "Dana B. Laustsen"
Dana B. Laustsen, P. Eng.

B-1

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 (USA) Corporation ("Enerplus"):

1.     Pursuant to the request of Enerplus, we have evaluated and reviewed the reserves data of certain properties as of December 31, 2006. The reserves data includes the following:

(a)(i)     proved and proved-plus-probable oil and gas reserves estimated as of December 31, 2006, 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 of December 31, 2006, 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.

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

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

   presented in the COGE Handbook.

4.      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 percent, evaluated as of December 31, 2006, 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	Description and Effective Date of Evaluation	Location of Reserves (Country or  Foreign Geographic Area)	Audited		Evaluated	Reviewed		Total
			(in US$ thousands)
DeGolyer and MacNaughton	Appraisal Report as of December 31, 2006 on Certain Properties owned by Enerplus Resources (USA) Corporation	Montana and North Dakota	Not Applicable	$	783,913	Not Applicable	$	783,913

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	Submitted, "DEGOLYER AND MACNAUGHTON"
Dallas, Texas, USA February 1, 2007	DeGolyer and MacNaughton
	/s/  PAUL J. SZATKOWSKI
	Paul J. Szatkowski, P.E. Senior Vice President DeGolyer and MacNaughton

C-2

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, 2006 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, 2006 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 & Chief Executive Officer

"Garry A. Tanner"

Garry A. Tanner
Executive Vice President &
Chief Operating Officer

"Harry B. Wheeler"

Harry B. Wheeler
Director

"W.C. (Mike) Seth"

W.C. (Mike) Seth
Director

March 12, 2007

D-2

APPENDIX "E"

AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE
PURSUANT TO MULTILATERAL INSTRUMENT 52-110

A.    The Audit & Risk Management Committee's Charter

        The charter of the Audit & Risk Management Committee (the "Committee") of the board of directors of EnerMark is attached as Schedule 1 to this Appendix "E".

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.

C.    Relevant Education and Experience

Name (Director Since)

Principal Occupation and Biography

Mr. Robert L. Normand (DSC, C.A.) (March 1998) Other Public Directorships  •    Quebecor World Inc. (commercial print media services)  •    Aurizon Mines Ltd. (gold mining)  •    ING Canada Inc. (property and casualty insurance)  •    Sportscene Group Inc. (chain of restaurants)  •    Fonds d'Investissement REA (mutual fund)

Mr. Normand is a corporate director and has served as a director of several private and public corporations operating in various fields of the economy. In addition to serving as a director of the public companies listed herewith, he is presently a director of Greenfield Ethanol Inc. (a private manufacturing company). Mr. Normand acted as an external auditor for Richter Usher & Vineber and Coopers & Lybrand until 1968 and held accounting responsibilities with two companies before joining Gaz Métropolitain late in 1972 as Assistant Chief Financial Officer. Mr. Normand ultimately held the position of Chief Financial Officer from 1980 until his retirement in 1997. Mr. Normand graduated from l'École des Hautes Études Commerciales (Université de Montréal) in 1966 (dec. commercial science), received a Chartered Accountant designation and became a member of the Québec Institute of Chartered Accountants the same year. Mr. Normand was President of the Financial Executives Institute Canada in 1992, Vice President U.S. in 1993 and is an active member of the Montréal Chapter. He is also a member of the Institute of Corporate Directors.

E-1

Name (Director Since)	Principal Occupation and Biography
Mr. Glen D. Roane (B.A., MBA) (June 2004) Other Public Directorships  •    Destiny Resource Services Corp. (oil and gas service business)  •    Badger Income Fund (provider of non-destructive excavation services)	Mr. Roane is a corporate director and has served as a board member of many TSX-listed companies including (in addition to those public entities listed herewith of which he currently serves s a director), Repap Enterprises Inc., Ranchero Energy Inc., Forte Resources Inc., Valiant Energy Inc., Maxx Petroleum Ltd. and NQL Energy Services Inc., since his retirement from TD Asset Management Inc., a subsidiary of The Toronto-Dominion Bank (a publicly traded Canadian chartered bank) in 1997. Mr. Roane spent almost 20 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. In addition to serving as a director of the public entities listed below, Mr. Roane is the Chairman of the board of directors of Flexpipe Systems Inc., a private energy services company. Mr. Roane holds a Bachelor of Arts and an MBA from Queen' University in Kingston, Ontario.
Mr. Harry B. Wheeler (B.A., B.Sc. (Geology)) (January 2001) Other Public Directorships  •    Nil	Mr. Wheeler has been the President of Colchester Investments Ltd., a private investment firm, since 2000. From 1962 to 1966, Mr. Wheeler worked with Mobil Oil in Canada and Libya and from 1967 to 1972 was employed by International Resources Ltd., in London, England and Denver, Colorado. He was a Director of Quintette Coal Ltd., Vice President of Amalgamated Bonanza Petroleum Ltd. and operator of his private company before founding Cabre Exploration Ltd. ("Cabre"), a public oil and gas company, in 1980. Mr. Wheeler was Chairman of Cabre until it was acquired by EnerMark Income Fund (a predecessor of Enerplus) in December 2000. Mr. Wheeler is currently a director of the Alberta Motor Association and its subsidiary, Bridgewater Bank. Mr. Wheeler graduated from the University of British Columbia in 1962 with a degree in Geology.

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 2006 and 2005 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.

E-2

E.    External Auditor Service Fees

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

	2006		2005
	(in $ thousands)
Audit fees(1)	$	763.9	$	409.2
Audit-related fees(2)		—		—
Tax fees(3)		1,211.3		138.5
All other fees(4)		—		—
	$	1,975.2	$	547.7

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".

E-3

SCHEDULE 1 TO APPENDIX "E"

AUDIT & RISK MANAGEMENT COMMITTEE

CHARTER

I.     AUTHORITY

        The Audit & Risk Management Committee (the "Committee") of the Board of Directors (the "Board") of the Fund 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.

        Because of the Committee's demanding role and responsibilities, the Corporate Governance and Nominating Committee reviews any invitation to Committee members to join the audit committee of any other company or corporation. Where a member of the Committee simultaneously serves on the audit committee of more than three (3) public companies, including the Committee, the Board determines whether such simultaneous service impairs the ability of such member to serve effectively on the Committee.

        Members of the Committee do not receive any compensation from the Fund other than compensation as directors and committee members. Prohibited compensation includes fees paid, directly or indirectly, for services as consultant or as legal or financial advisor, regardless of the amount, but excludes any compensation approved by the Board and that is paid to the directors as members of the Board and its committees.

II.    PURPOSE OF THE COMMITTEE

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

 1. financial reporting and continuous disclosure of the Fund;

 2. the Fund's internal controls and policies, the certification process and compliance with regulatory requirements over financial matters;

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

 4. monitoring the manner in which the business risks of the Fund are being identified and 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 senior management of the Fund.

III.  COMPOSITION AND COMPETENCY OF THE COMMITTEE

        Each member of the Committee shall be unrelated to the Fund 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 and at least one member of the Committee shall have accounting or related financial management expertise — "literate" or "literacy" and "expertise" as defined by applicable securities legislation. Members are encouraged to enhance their understanding of current issues through means of their preference.

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IV.    MEETINGS OF THE COMMITTEE

        The Committee shall meet with such frequency and at 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 Corporation's external auditors in separate executive sessions to 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

Evaluating and monitoring the performance and independence of external auditors

  1. Make recommendations to the Board on the appointment of external auditors of the Fund;

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

  3.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 auditors' performance. Approve audit fees:

   (a) Review annually the external auditors' quality control, any material issues raised by the most recent quality control review, or peer review, of the firm, or any inquiry or

    investigation by governmental or professional authorities of the firm within the preceding five years, and any steps taken to deal with such issues;

(b)Obtain assurances from the external auditors that the audit was conducted in accordance with Canadian and US generally accepted auditing standards; and

   (c) Ensure that management interacts professionally with the auditors and confirm such behavior annually with both parties.

  4.  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 detailing all relationships between the external auditors and

       the Fund;

 (b)reviewing and approving the Fund's hiring policies regarding partners, employees and former partners and employees of current and former 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;

 (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;

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(g)	have a private meeting with the external auditors at every quarterly Committee meeting;
(h)	obtain annually the auditors’ views on competency and integrity of the audit committee and senior financial executives;

Oversight of annual and quarterly financial statements, management discussion and analysis and press releases

5. Review and approve the annual audit plan of the external auditors, including the scope of audit activities, and monitor such plan’s progress and results quarterly and at year end;

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

7. Review the appropriateness of management’s representation letter transmitted to the external auditors;

8. Receipt of certifications from the CEO and CFO;

9. Review with management the adequacy of financial results and disclosure in the management discussion and analysis and press release and recommend approval to the Board:

(a)	obtain satisfactory answers from management following the review of the financial documents;
(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; and
(i)	management’s acknowledgement of its responsibility towards the financial statements.
(j)	significant legal, compliance or regulatory matters that may have a material effect on the financial statements or the business of the organization (including material notices to, or inquiries received from, governmental agencies); and
(k)	receive the report from the Reserves Committee over the appropriateness of reported reserves and resources.

Oversight of financial reporting process, internal controls, the continuous disclosure and certification process and compliance with regulatory requirements

10.	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 any developments and responses on reports received thereunder;
11.	Review the adequacy and effectiveness of the financial reporting system and internal control policies and procedures with the external auditors and management. Ensure that the Fund complies with all new regulations in this regard;
12.	Review with management the Fund’s internal controls, and evaluate whether the Fund is operating in accordance with prescribed policies and procedures;

E-6

	13.	Review with management and the external auditors any reportable condition and material weaknesses affecting internal controls;
	14.	Review the management disclosure and oversight Committee’s CEO and CFO certification processes to ensure compliance with US and Canadian requirements.
	15.	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 the Fund;
	16.	Review annually the report of the external auditor on management’s assessment of the Fund’s internal control over financial reporting describing any material issues raised by the most recent reviews of internal controls and management information systems or by any inquiry or investigation by governmental or professional authorities and any recommendations made and steps taken to deal with any such issues;
Review of Business Risks
	17.	Review with management the process followed to do the Fund’s risk assessment and the policies to monitor, mitigate and report such business risks;
Other Matters
	18.	Review of appointment or dismissal of senior financial executives;
	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.	Review the disclosure made in the Annual Report, Annual Information Form, 40-F and the Information Circular regarding the Audit & Risk Management Committee;
	21.	Establish and maintain a free and open means of communication between the Board, the Committee, the external auditors, and management;
	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; and
	23.	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. This review forms part of the review process undertaken by the Corporate Governance and Nominating Committee, which reports its findings to the Board.

        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 the Fund complies with all laws and regulations, the spirit and intent of this Charter is that the Committee shall take reasonable steps to encourage the Fund to act in full compliance therewith.

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APPENDIX "F"

SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION

        The following disclosures have been prepared in accordance with the provisions of the Financial Accounting Standards Board's Statement No. 69 — Disclosures about Oil and Gas Producing Activities ("SFAS No. 69"). The disclosures include reserves and costs attributable to both our conventional crude oil and natural gas operations as well as our SAGD — recoverable bitumen activities related to the Joslyn Project. The Proved Reserves quantities disclosed herein are determined according to the definition of "proved reserves" under NI 51-101 which differs from the definition provided in the SEC rules, however the difference should not be material. See "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information" in this Annual Information Form.

        All cost information in this section is stated in Canadian dollars and is calculated in accordance with United States of America Generally Accepted Accounting Principles ("U.S. GAAP").

A.    Proved Bitumen, Oil and Natural Gas Reserve Quantities

        Users of this information should be aware that the process of estimating quantities of "Proved Developed" and "Proved Undeveloped" bitumen, oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

        Proved Reserves are the estimated quantities of bitumen, oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions that existed at year end. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Fund's reserves to be materially different from that presented.

        Proved Developed Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Undeveloped Reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

        Subsequent to December 31, 2006, no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of Proved Reserves as of that date.

        The Fund's Proved bitumen oil, natural gas liquids, and natural gas reserves are located in western Canada, primarily in Alberta, British Columbia, and Saskatchewan, as well as in Montana and North Dakota (and since January 31, 2007, Wyoming) in the United States. The Fund's Proved Reserves summarized in the following

F-1

chart represent the Fund's lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any Crown, freehold and overriding royalties:

	Canada									United States						Total
	Oil and NGLs			Natural Gas			Bitumen			Oil and NGLs			Natural Gas			Oil and NGLs			Natural Gas			Bitumen
	(Mbbls)			(Mmcf)			(Mbbls)			(Mbbls)			(Mmcf)			(Mbbls)			(Mbbls)			(Mmcf)
Proved Developed and Undeveloped Reserves at December 31, 2003		93,418			689,900			—			—			—			93,418			689,900			—
Purchases of reserves in place		12,437			94,354			—			—			—			12,437			94,354			—
Sales of reserves in place		(162	)		(1,860	)		—			—			—			(162	)		(1,860	)		—
Discoveries and extensions		2,704			22,399			—			—			—			2,704			22,399			—
Revisions of previous estimates		(1,449	)		(50,066	)		—			—			—			(1,449	)		(50,066	)		—
Improved recovery		6,113			115,000			—			—			—			6,113			115,000			—
Production		(8,902	)		(77,369	)		—			—			—			(8,902	)		(77,369	)		—
Proved Developed and Undeveloped Reserves at December 31, 2004		104,159			792,358			—			—			—			104,159			792,358			—
Purchases of reserves in place		485			6,440			—			20,198			10,803			20,683			17,243			—
Sales of reserves in place		(2,258	)		(10,414	)		—			—			—			(2,258	)		(10,414	)		—
Discoveries and extensions		735			33,834			—			—			—			735			33,834			—
Revisions of previous estimates		9,189			14,543			9,215			624			792			9,813			15,335			9,215
Improved recovery		3,642			28,700			—			—			—			3,642			28,700			—
Production		(9,283	)		(78,737	)		—			(885	)		(486	)		(10,168	)		(79,223	)		—
Proved Developed and Undeveloped Reserves at December 31, 2005		106,669			786,724			9,215			19,937			11,109			126,606			797,833			9,215
Purchases of reserves in place		1,044			4,162			—			333			283			1,377			4,445			—
Sales of reserves in place		(30	)		(107	)		(532	)		—			—			(30	)		(107	)		(532	)
Discoveries and extensions		1,981			22,854			—			367			321			2,348			23,175			—
Revisions of previous estimates		(1,895	)		(44,035	)		(294	)		218			1,318			(1,677	)		(42,717	)		(294	)
Improved recovery		2,788			22,347			—			1,727			1,111			4,515			23,458			—
Production		(9,259	)		(74,484	)		—			(3,113	)		(1,804	)		(12,372	)		(76,288	)		—
Proved Developed and Undeveloped Reserves at December 31, 2006		101,298			717,461			8,389			19,469			12,338			120,767			729,799			8,389
Proved Developed Reserves
December 31, 2003		88,492			605,700			—			—			—			88,492			605,700			—
December 31, 2004		98,712			672,960			—			—			—			98,712			672,960			—
December 31, 2005		101,048			652,825			—			13,354			7,442			114,402			660,267			—
December 31, 2006		95,734			584,846			2,687			18,977			11,961			114,711			596,807			2,687

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B.    Capitalized Costs Related to Oil and Gas Producing Activities

        The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to the Fund's oil and gas exploration, development and producing activities are as follows:

	2006			2005			2004
	(in $ thousands)
Capitalized costs(1)	$	4,689,444		$	4,141,627		$	3,145,699
Less accumulated depletion, depreciation and amortization		(1,608,186	)		(1,212,145	)		(892,786	)
Net capitalized costs	$	3,081,258		$	2,929,482		$	2,252,913

Note:

(1) Includes capitalized costs of proved and unproved properties.

C.    Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

        Costs incurred in connection with oil and gas producing activities are as follows:

	For the Year Ended December 31, 2006
	Canada		United States		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	35,323	$	15,990	$	51,313
Unproved		20,006		201		20,207
Exploration costs		32,510		1,202		33,712
Development costs		325,459		115,284		440,743
Asset retirement costs		17,743		588		18,331
	$	431,041	$	133,265	$	564,306

	For the Year Ended December 31, 2005
	Canada		United States		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	91,489	$	589,613	$	681,102
Unproved		10,633		22,926		33,559
Exploration costs		9,914		1,750		11,664
Development costs		319,038		27,354		346,392
Asset retirement costs		13,789		1,766		15,555
	$	444,863	$	643,409	$	1,088,272

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	For the Year Ended December 31, 2004
	Canada		United States(1)		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	623,166	$	—	$	623,166
Unproved		15,918		—		15,918
Exploration costs		—		—		—
Development costs		204,116		—		204,116
Asset retirement costs		46,823		—		46,823
	$	890,023	$	—	$	890,023

Note:

(1) The Fund had no oil and gas producing activities in the United States during 2004.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties, including an allocation of purchase price on business combinations that result in property acquisitions. Development costs include the costs of drilling and equipping development wells and facilities to extract, gather and store oil and gas, along with an allocation of overhead. Development costs also include capitalized interest for development projects that have not reached commercial production. Exploration costs include costs related to the discovery and the drilling and completion of exploratory wells in new crude oil and natural reservoirs. Asset retirement costs represent capitalized asset retirement costs during the year. No gains or losses on retirement activities were realized, due to settlements approximating the estimates.

D.    Results of Operations for Oil and Gas Producing Activities

        The following table sets forth revenue and direct cost information relating to the Fund's oil and gas producing activities for the years ended December 31.

	For the Year Ended December 31, 2006
	Canada			United States		Total
	(in $ thousands)(1)
Revenue
Sales(2)	$	1,082,644		$	219,519	$	1,302,163
Deduct
Production Costs(3)		266,493			7,357		273,850
Depletion, depreciation, amortization, accretion and impairment		295,975			111,232		407,207
Current and Deferred income tax provision		(55,409	)		19,845		(35,564	)
Results of operations for oil and gas producing activities	$	575,585		$	81,085	$	656,670

	For the Year Ended December 31, 2005
	Canada		United States		Total
	(in $ thousands)(1)
Revenue
Sales(2)	$	1,189,551	$	64,035	$	1,253,586
Deduct
Production Costs(3)		241,656		2,067		243,723
Depletion, depreciation, amortization, accretion and impairment		297,678		31,817		329,495
Current and Deferred income tax provision		25,248		9,384		34,632
Results of operations for oil and gas producing activities	$	624,969	$	20,767	$	645,736

F-4

	For the Year Ended December 31, 2004
	Canada			United States(4)		Total
	(in $ thousands)(1)
Revenue
Sales(2)	$	918,811		$	—	$	918,811
Deduct
Production Costs(3)		221,570			—		221,570
Depletion, depreciation, amortization, accretion and impairment		251,494			—		251,494
Current and Deferred income tax provision (recovery)		(35,926	)		—		(35,926	)
Results of operations for oil and gas producing activities	$	481,673		$	—	$	481,673

Notes:

(1) The costs in the schedules exclude corporate overhead, interest expense and other costs which are not directly related to oil and gas producing activities.

(2) Sales are presented net of royalties and third party obligations.

(3) Production costs include transportation costs.

(4) The Fund had no oil and gas producing activities in the United States during 2004.

E.    Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Bitumen, Oil and Natural Gas Reserve Quantities

        The following information has been developed utilizing procedures described by SFAS No. 69 and based on bitumen crude oil and natural gas reserve and production volumes estimated by the independent engineering consultants of the Fund. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Fund or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the "standardized measure of discounted future net cash flows" be viewed as representative of the current value of the Fund's reserves.

        The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the period end date. It is expected that material revisions to some estimates of bitumen, crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

        Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of Probable Reserves as well as Proved Reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

        The following tables set forth the standardized measure of discounted future net cash flows from projected production of the Fund's bitumen, crude oil and natural gas reserves.

	As at December 31, 2006
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	10,197	$	1,185	$	11,382
Future production costs		3,826		98		3,924
Future development and asset retirement costs		569		22		591
Future income tax expenses		—		240		240
Future net cash flows	$	5,802	$	825	$	6,627
Deduction: 10% annual discount factor		2,744		305		3,049
Standardized measure of discounted future net cash flows	$	3,058	$	520	$	3,578

F-5

	As at December 31, 2005
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	13,556	$	1,397	$	14,953
Future production costs		3,720		88		3,808
Future development and asset retirement costs		513		90		603
Future income tax expenses		—		311		311
Future net cash flows	$	9,323	$	908	$	10,231
Deduction: 10% annual discount factor		4,496		329		4,825
Standardized measure of discounted future net cash flows	$	4,827	$	579	$	5,406

	As at December 31, 2004
	Canada		United States(1)		Total
	(in $ millions)
Future cash inflows	$	8,836	$	—	$	8,836
Future production costs		2,724		—		2,724
Future development and asset retirement costs		353		—		353
Future income tax expenses		—		—		—
Future net cash flows	$	5,759	$	—	$	5,759
Deduction: 10% annual discount factor		2,825		—		2,825
Standardized measure of discounted future net cash flows	$	2,934	$	—	$	2,934

Note:

(1) The Fund had no oil and gas producing activities in the United States during 2004.

F.     Changes in Standardized Measure of Discounted Future Cash Flow Relating to Proved Oil and Natural Gas Reserves

        The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

	2006			2005			2004
	(in $ millions)
Beginning of year	$	5,406		$	2,934		$	2,222
Sales of oil and natural gas produced, net of production costs		(1,028	)		(1,009	)		(697	)
Net changes in sales prices and production costs		(1,963	)		2,170			523
Changes in previously estimated development costs incurred during the period		240			113			(107	)
Changes in estimated future development costs		(210	)		(308	)		(177	)
Extension, discoveries and improved recovery, net of related costs		725			424			292
Purchase of reserves in place		31			952			497
Sales of reserves in place		(3	)		(30	)		(33	)
Net change resulting from revisions in previous quantity estimates		(130	)		126			228
Accretion of discount		442			230			186
Net change income taxes		68			(196	)		—
End of year	$	3,578		$	5,406		$	2,934

Note:

(1) The schedules above are calculated using year-end prices, costs, statutory tax rates and existing Proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

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Enerplus Resources Fund
The Dome Tower
3000, 333 - 7th Avenue S.W.
Calgary, Alberta, Canada
T2P 2Z1
Telephone: 403.298.2200
Toll free: 1.800.319.6462
Fax: 403.298.2211
www.enerplus.com