Exhibit 99.1

ANNUAL INFORMATION FORM

For the year ended December 31, 2007

March 13, 2008

TABLE OF CONTENTS

	Page		Page
GLOSSARY OF TERMS	iii	Equity Investments	49
ABBREVIATIONS AND CONVERSIONS	vi	Health, Safety and Environment	49
PRESENTATION OF ENERPLUS’ OIL AND GAS RESERVES, RESOURCES AND		Insurance	51
PRODUCTION INFORMATION	vii	Personnel	51
PRESENTATION OF ENERPLUS’ FINANCIAL INFORMATION	xi	INFORMATION RESPECTING ENERPLUS RESOURCES FUND	52
FORWARD-LOOKING STATEMENTS AND INFORMATION	xi	Description of the Trust Units and the Trust Indenture	52
STRUCTURE OF ENERPLUS RESOURCES FUND	1	Description of the Royalty Agreements and Other Payments Made to the Fund	59
GENERAL DEVELOPMENT OF ENERPLUS RESOURCES FUND	3	Management and Corporate Governance	60
Historical Overview	3	Unitholder Rights Plan	60
Developments in the Past Three Years	3	DEBT OF ENERPLUS	61
Events Subsequent to December 31, 2007	5	Bank Credit Facility	61
OPERATIONAL INFORMATION	7	Senior Unsecured Notes	62
Overview	7	DISTRIBUTIONS TO UNITHOLDERS	63
Description of Principal Properties and Operations	7	Cash Distributions	63
Summary of Principal Production Locations	9	Distribution History	64
Costs Incurred in 2007 and Summary of Capital Expenditures	9	Canadian Tax Reporting Matters	64
Exploration and Development Activities	10	U.S. Tax Reporting Matters	64
Oil and Natural Gas Wells and Unproved Properties	11	INDUSTRY CONDITIONS	66
Enerplus’ Play Types	11	RISK FACTORS	73
Quarterly Production History	21	MARKET FOR SECURITIES	91
Quarterly Netback History	22	DIRECTORS AND OFFICERS	92
Abandonment and Reclamation Costs	24	INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	95
Tax Horizon	24	MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF
Marketing Arrangements and Forward Contracts	24	SECURITYHOLDERS	95
OIL AND NATURAL GAS RESERVES	26	INTERESTS OF EXPERTS	96
Overview of Reserves	26	REGISTRAR AND TRANSFER AGENT	96
Summary of Aggregate Enerplus Reserves	27	ADDITIONAL INFORMATION	96
Summary of Conventional Oil and Natural Gas Reserves	29	APPENDIX “A”  - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED
Summary of Joslyn Project Bitumen Reserves	38	RESERVES EVALUATOR OR AUDITOR	A-1
Reconciliation of Reserves	41	APPENDIX “B”  - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED
Undeveloped Reserves	45	RESERVES EVALUATOR OR AUDITOR	B-1
Significant Factors or Uncertainties	45	APPENDIX “C”  - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED
Proved and Probable Reserves Not on Production	45	RESERVES EVALUATOR OR AUDITOR	C-1
SUPPLEMENTAL OPERATIONAL INFORMATION	46	APPENDIX “D”  - REPORT OF MANAGEMENT AND DIRECTORS ON
Finding and Development and Finding, Development and Acquisition Costs	46	RESERVES DATA AND OTHER INFORMATION	D-1
Acquisitions and Divestments	49	APPENDIX “E”  - AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE	E-1
		APPENDIX “F”  - SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION	F-1
		APPENDIX “G”  - INFORMATION REGARDING FOCUS ENERGY TRUST	G-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;

“Bank Credit Facility” has the meaning assigned thereto under “Debt of Enerplus”;

“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 10o API;

“COGE Handbook” means the “Canadian Oil and Gas Evaluation Handbook” prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time;

“Credit Facilities” has the meaning assigned thereto under “Debt of Enerplus”;

“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;

“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 the Fund;

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

“Focus” means Focus Energy Trust, an open-ended unincorporated investment trust established under the laws of the Province of Alberta;

“Focus Exchangeable LP Unitholders” means the holders from time to time of Focus Exchangeable LP Units;

“Focus Exchangeable LP Units” means the Class B limited partnership units of Focus LP, which are non-transferable and are exchangeable for no additional consideration into Trust Units on the basis of 0.425 of a Trust Unit for each Focus Exchangeable LP Unit;

“Focus LP” means Focus Limited Partnership, a limited partnership established under the laws of Alberta and a subsidiary of the Fund;

“Focus LP A Units” means the Class A limited partnership units of Focus LP, all of which are held, directly or indirectly, by the Fund;

“Focus LP Agreement” means the amended and restated limited partnership agreement dated February 13, 2008 of Focus LP, as such may be amended, supplemented or restated from time to time;

“Focus LP General Partner” means FET Management Ltd., a corporation organized under the Business Corporations Act (Alberta) and an indirect wholly owned subsidiary of the Fund;

“Focus LP Support Agreement” means the amended and restated support agreement dated February 13, 2008 among the Fund, Focus LP and EnerMark, as such may be amended, supplemented or restated from time to time;

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“Focus LP Voting and Exchange Agreement” means the amended and restated voting and exchange trust agreement dated February 13, 2008 among the Fund, Focus LP and CIBC Mellon Trust Company, as such may be amended, supplemented or restated from time to time;

“Focus Properties” means the oil and natural gas properties of Focus prior to its acquisition by Enerplus on February 13, 2008;

“Fund” means Enerplus Resources Fund;

“GAAP” means generally accepted accounting principles;

“GLJ” means GLJ Petroleum Consultants Ltd., independent petroleum consultants;

“GLJ Oil Sands Resources Report” means the independent engineering evaluation of the contingent and prospective resources attributable to Enerplus’ interests in the Kirby Project and the Joslyn Project (together with interests in certain minor non-operated oil sands projects) prepared by GLJ dated February 22, 2008 and effective December 31, 2007;

“GLJ Reserves Report” means the independent engineering evaluation of the reserves attributable to Enerplus’ interest in the Joslyn Project prepared by GLJ dated February 6, 2008 and effective December 31, 2007, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus’ reserves reporting) dated December 31, 2007;

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

“Joslyn 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;

“Kirby” means Kirby Oil Sands Partnership, an Alberta general partnership;

“Kirby Lease” means, collectively, seven separate oil sands leases on a total area of 43,360 acres in the Kirby area of northeastern Alberta in Townships 073 through 075, Ranges 07 through 10, W4M, that expire on various dates from December 13, 2015 to September 27, 2021;

“Kirby Project” means the development of the Kirby Lease;

“Laricina” means Laricina Energy Ltd., a private oil sands corporation organized under the Business Corporations Act (Alberta);

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

“NSAI” means Netherland, Sewell & Associates, Inc., independent petroleum consultants;

“NSAI Report” means the independent engineering evaluation of Enerplus’ U.S. conventional oil, NGLs and natural gas interests prepared by NSAI dated February 21, 2008 and effective December 31, 2007, utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus’ reserves reporting) dated December 31, 2007;

“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 as of December 31, 2007 being EnerMark, ERC, ECT and Enerplus USA);

“Paddock” means Paddock Lindstrom & Associates Ltd., independent petroleum consultants;

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“Paddock Focus Report” means the independent engineering evaluation of Focus’ oil, NGLs and natural gas interests prepared by Paddock dated February 11, 2008 and effective December 31, 2007 utilizing commodity price forecasts of Sproule (for internal consistency in Enerplus’ reserves reporting) dated December 31, 2007;

“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;

“Senior Unsecured Notes” means the US$229 million principal amount of senior unsecured notes issued by EnerMark, as described under “Debt of Enerplus”;

“SIFT Tax” has the meaning ascribed thereto under “General Development of Enerplus Resources Fund  - Developments in the Past Three Years  - Changes to Taxation of Income Trusts”;

“Special Voting Right” means the special voting right issued by the Fund to the Voting and Exchange Trustee entitling the holder thereof to vote, consent to, or otherwise act at a meeting or in respect of a resolution of the Fund’s unitholders, and representing the number of votes that the Focus Exchangeable LP Unitholders would be entitled to had the Focus Exchangeable LP Unitholders exchanged all of the Focus Exchangeable LP Units then held by such holders for Trust Units immediately prior to the record date set for such meeting or at such other time as may be determined by applicable law for determining the Fund’s unitholders entitled to so vote, consent or otherwise act at such a meeting or in respect of such a resolution;

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

“Sproule Report” means the independent engineering evaluation of Enerplus’ Canadian conventional oil, NGLs and natural gas interests prepared by Sproule dated February 15, 2008 and effective December 31, 2007, utilizing commodity price forecasts of Sproule dated December 31, 2007;

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

“Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c.1 (5th Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time;

“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 November 8, 2007 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

“Voting and Exchange Trustee” means CIBC Mellon Trust Company, or its successor as trustee under the Focus LP Voting and Exchange Agreement;

“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	Mcf	one thousand cubic feet
bbls	barrels, with each barrel representing 34.972 imperial gallons or 42 U.S. gallons	Mcf/d	one thousand cubic feet per day
bbls/d	barrels per day	MMbbls	one million barrels
Bcf	billion cubic feet	MMBOE	one million barrels of oil equivalent
Bcf/d	billion cubic feet per day	mmbtu	one million British Thermal Units
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.	MMcf	one million cubic feet
BOE/d	barrels of oil equivalent per day	MMcf/d	one million cubic feet per day
Mbbls	one thousand barrels	NGLs	natural gas liquids
MBOE	one thousand barrels of oil equivalent

Note:

(1) 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.

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 reserves and operational information of Enerplus 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. 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 NSAI 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, 2007 and the information contained in the Annual Information Form has been prepared as of March 13, 2008. This Annual Information Form also contains certain supplemental operational and reserves information with respect to Enerplus not required to be disclosed under NI 51-101.

Additionally, Appendix “G” to this Annual Information Form, titled “Information Regarding Focus Energy Trust,” contains certain oil and gas reserves and operational information of Focus as at and for the year ended December 31, 2007, prepared in accordance with NI 51-101. Enerplus acquired all of the assets of Focus on February 13, 2008 and is supplementing Enerplus’ 2007 year-end disclosure with similar disclosure with respect to Focus.

Certain of the following definitions and guidelines are contained in the Glossary to NI 51-101 contained in Canadian Securities Administrators Staff Notice 51-324 (“CSA Notice 51-324”), which incorporates certain definitions from the COGE Handbook. Readers should consult CSA Notice 51-324 and the COGE Handbook for additional explanation and guidance.

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 and Focus 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’ and Focus’ 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 such oil and natural gas reserves does not represent the fair market value of such reserves. See “Oil and Natural Gas Reserves  - Overview of Reserves” for additional information.

Data on oil and natural gas reserves contained in this Annual Information Form has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, 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 (as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves (defined differently from the SEC rules) but also Probable Reserves (each as defined in NI 51-101 and described below). As a result, in this Annual Information Form, Enerplus has disclosed reserves designated as “Probable Reserves” and “Proved plus Probable Reserves”. Probable Reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than Proved 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. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, “company interest”) volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, Enerplus has determined and disclosed estimated future net revenue from its and Focus’ reserves using forecast prices and costs (as well as certain supplemental information using constant 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 of the foregoing, Enerplus’ and Focus’ reserve estimates and production volumes may not be comparable to those made by companies utilizing United States reporting and disclosure standards. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see “--  Disclosure of Contingent Resources” below.

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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

In this Annual Information Form, Enerplus has disclosed estimated volumes of “contingent resources” that have been prepared by GLJ pursuant to the GLJ Oil Sands Resources Report and which relate to the Kirby Lease and certain mineable portions of the Joslyn Lease.

“Resources” are quantities of petroleum that are estimated to exist originally in naturally occurring accumulations, including the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

“Contingent resources” are defined as those quantities of petroleum estimated, on a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associated with a project in the early project stage.

Resources and contingent resources do not constitute, and should not be confused with, reserves. See “Operational Information  - Enerplus’ Play Types  - Oil Sands” and “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.”

Interests in Reserves, Production, Wells and Properties

In addition to the terms having defined meanings set forth in CSA Notice 51-324, 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, plus Enerplus’ royalty interests in production or reserves. See “--  Disclosure of Reserves and Production Information” above.

“gross” means:

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

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(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 estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of given date, based on: analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves may be divided into proved and probable categories (as well as possible reserves, which Enerplus does not report) according to the degree of certainty associated with the estimates.

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

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• “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

“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).

“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, 2007, held constant throughout the estimated lives of the properties to which the estimate applies (being Enerplus’ posted price for oil and the spot price for gas, after historical adjustments for transportation, gravity and other factors); 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 16 to the Fund’s audited consolidated financial statements for the year ended December 31, 2007, which are available on the Fund’s SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the annual report on Form 40-F filed with the SEC together with this Annual Information Form, 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”, “strategy”, “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;

• Enerplus’ business strategy and planned acquisition and development strategy, including planned drilling programs;

• 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 development of the Kirby Project and the Joslyn Project, and Enerplus’ strategy for growth;

• Enerplus’ future operating and financial results;

• future abandonment and reclamation costs;

• treatment under governmental and other regulatory regimes and tax, environmental and other laws; and

• future income tax laws and royalty regimes.

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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, bitumen, 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, royalty regimes and incentive programs relating to the oil and gas industry and income trusts;

• 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;

• constraints on, or the unavailability of, adequate pipeline and transportation capacity to deliver Enerplus’ production to market;

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

• changes in general economic, market (including credit 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, 2007, which is available through the internet on Enerplus’ SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the annual report on Form 40-F filed with the SEC together with this Annual Information Form, 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.

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ENERPLUS RESOURCES FUND

Annual Information Form

for the year ended December 31, 2007

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 securities issued by its direct wholly-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”, “Oil and Natural Gas Reserves” and “Supplemental Operational Information” for information regarding the operations and oil and natural gas reserves and contingent bitumen resources of Enerplus. As of December 31, 2007, the Fund’s material Operating Subsidiaries were EnerMark, ERC, ECT and Enerplus USA.

Each of EnerMark and ERC 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, ECT and Enerplus USA are indirectly owned by the Fund.

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Organizational Structure

The simplified organizational structure of Enerplus as of December 31, 2007, 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. An updated simplified organizational structure chart of Enerplus after giving effect to Enerplus’ acquisition of Focus on February 13, 2008 is included in Appendix “G”  - Information Regarding Focus Energy Trust.

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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 TriLoch Resources Inc.

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

Acquisition of Lyco Energy Corporation and Sleeping Giant LLC

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

On October 4, 2005, Enerplus completed the acquisition of Sleeping Giant LLC, a private U.S. company. Total consideration paid for Sleeping Giant LLC was approximately $111.9 million and was financed through existing credit facilities. Enerplus also assumed positive working capital of $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. 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  - Enerplus’ Play Types  - Oil Sands  - Joslyn Project”.

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In early 2006, Enerplus sold a 1% working interest in the Joslyn Project in exchange for equity in Laricina, a 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 was 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.

Changes to Taxation of Income Trusts

On October 31, 2006, the Canadian Federal Minister of Finance proposed to subject certain types of income of publicly traded mutual fund trusts to tax (the “SIFT Tax”) at rates comparable to the combined federal and provincial corporate tax rates. This is accomplished by eliminating the trust’s ability to deduct income distributions to unitholders, taxing the trust’s income at corporate rates and treating distributions to unitholders as taxable dividends. The legislation governing the SIFT Tax (the “SIFT Provisions”) became law on June 22, 2007.

The SIFT Provisions are not expected to apply to the Fund prior to 2011 provided the Fund restricts itself to “normal growth” during the transitional period ending December 31, 2010. However, any “undue expansion” during this transitional period may cause the SIFT Tax to apply to the Fund before January 1, 2011. For these purposes, “normal growth” includes equity growth within certain “safe harbour” limits, measured by reference to a “specified investment flow through’s” (“SIFT”) market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFTs issued and outstanding publicly traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits are 40 percent for the period from November 1, 2006 to December 31, 2007, and 20 percent each for calendar year 2008, 2009 and 2010. Moreover, these limits are cumulative, so that any unused limit for a period carries over into the subsequent period. Additional details of the parameters of “normal growth” include the following:

• new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those);

• replacing debt that was outstanding as of October 31, 2006, with new equity will not be considered growth for these purposes and will not affect the safe harbour; and

• the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006, will not be considered growth for those purposes and will not affect the safe harbour.

Enerplus’ and Focus’ combined market capitalization as of the close of trading on October 31, 2006, having regard only to the issued and outstanding publicly traded trust units of each at such date, was approximately $9.1 billion, which means the combined “safe harbour” equity growth amount for each of calendar year 2008, 2009 and 2010 is approximately $1.8 billion per year (in any case, not including equity (which includes convertible debentures) which could be issued to replace debt that was outstanding on October 31, 2006, which would result in the aggregate combined “safe harbour” growth amount to equal approximately $10 billion).

As a result of the enactment of the SIFT Provisions in 2007, the Fund’s future income taxes disclosed in its financial statements were adjusted to include temporary differences between the accounting and tax bases of the Fund’s assets and liabilities, as further described in Note 11 to the Fund’s audited consolidated financial statements for the year ended December 31, 2007. In addition, the reported estimated net present value of future net revenues from Enerplus’ oil and natural gas reserves on an “after-tax” basis now reflects the impact of the SIFT Tax on Enerplus’ reserves. Enerplus is currently evaluating alternatives to determine the optimal structure for its unitholders. However, it sees value in maintaining the Fund as a trust during the remaining transitional period which runs through the end of 2010 and currently intends to maintain its current structure during this period, unless circumstances arise that provide compelling reasons to change.

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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.

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 $61 million. This acquisition represented a modest addition to Enerplus’ assets in the United States and established 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 acquired a net royalty interest that was 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 or operating costs on the assets.

Acquisition of Kirby

On April 10, 2007, Enerplus acquired an undivided 90% interest in Kirby (including the managing partner’s 0.01% partnership interest) for aggregate consideration of $182.8 million, payable by the issuance of 1,104,945 Trust Units at a price of $49.55 per Trust Unit, and the remaining $128.1 million in cash. On June 22, 2007, Enerplus acquired the remaining 10% interest in Kirby for cash consideration of $20.3 million, for a total purchase price of $203.1 million. As part of the transaction, Enerplus also acquired the petroleum and natural gas rights owned by the vendors in the lands to which the Kirby Lease relates, excluding the petroleum and natural gas rights in any section of land on which there is an existing petroleum or natural gas well, but only to the deepest formation penetrated by such well.

For additional information relating to the Kirby Project, see “Operational Information  - Enerplus’ Play Types  - Oil Sands  - Kirby Project”.

Proposed Revisions to Alberta Royalty Regime

On October 25, 2007, the Government of Alberta unveiled a new royalty regime which would introduce new royalties for conventional oil, natural gas and bitumen effective January 1, 2009 that are linked to price and production levels and will apply to both new and existing oil sands projects and conventional oil and gas activities. For additional information regarding the various jurisdictions where Enerplus operates and has oil and gas production, see "Operational Information – Summary of Principal Production Locations". The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof. For additional details, see “Industry Conditions  - Royalties and Incentives” and “Risk Factors  - Risks Related to Enerplus’ Business and Operations  - The proposed new Alberta royalty regime may adversely impact Enerplus and its operations and reserves”.

Events Subsequent to December 31, 2007

Acquisition of Focus Energy Trust

On February 13, 2008, the Fund completed its acquisition of Focus pursuant to a plan of arrangement under the Business Corporations Act (Alberta). Pursuant to the arrangement, the Fund acquired all of the assets and assumed all of the liabilities of Focus, Focus unitholders received 0.425 of an Enerplus Trust Unit for each Focus trust unit, and all of the trust units of Focus were redeemed. The Fund issued an aggregate of 30,149,752 Trust Units to former Focus unitholders in the transaction.

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The holders of Focus Exchangeable LP Units did not exchange their Focus Exchangeable LP Units for Enerplus Trust Units pursuant to the arrangement, but following the arrangement the Focus Exchangeable LP Units are exchangeable for Enerplus Trust Units on the basis of 0.425 of an Enerplus Trust Unit for each Focus Exchangeable LP Unit. Similarly, the voting rights attached to the Focus Exchangeable LP Units, as well as the cash distributions and payments to be made on such units, have been adjusted in accordance with such exchange ratio.

In conjunction with the arrangement, Enerplus increased the size of its syndicated Bank Credit Facility by $400 million to $1.4 billion. The Bank Credit Facility continues to be unsecured and covenant-based with a revolving three-year term. See “Debt of Enerplus”.

The Fund intends to file a Business Acquisition Report in Form 51-102F4 in respect of the Focus acquisition within the period required by National Instrument 51-102.

For additional information regarding Focus, including its oil and gas reserves as at December 31, 2007 and certain other oil and gas operational information for the year ended December 31, 2007, as well as the combined oil and natural gas reserves of Enerplus and Focus as at December 31, 2007 (as if the acquisition had been completed as of that date), an updated simplified organizational structure chart of the Fund and its material subsidiaries and a description of the Focus Exchangeable LP Units and the agreements relating thereto, see “Information Regarding Focus Energy Trust” in Appendix “G” to this Annual Information Form.

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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, deep tight 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 approximately 99% drilling success by avoiding certain 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. 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 Report or NSAI 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, Wyoming and Utah. All of Enerplus’ major properties have related field production facilities and infrastructure to accommodate Enerplus’ production. Production volumes for the year ended December 31, 2007 from Enerplus’ properties consisted of approximately 47% crude oil and NGLs and 53% natural gas on a BOE basis. Enerplus’ 2007 average daily production was comprised of 34,506 bbls/d of crude oil, 4,104 bbls/d of NGLs and 262.2 MMcf/d of natural gas for a total of 82,319 BOE/d, a decrease of approximately 4% on a BOE basis when compared to 2006 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. Approximately 64% of Enerplus’ 2007 production was operated by Enerplus and the remaining 36% was operated by industry partners. As at December 31, 2007, the oil and natural gas property interests held by Enerplus were estimated to contain Proved plus Probable Reserves of 118,579 Mbbls of light and medium crude oil, 42,163 Mbbls of heavy crude oil, 63,498 Mbbls of bitumen, 15,612 Mbbls of NGLs and 1,202,291 MMcf of natural gas, for a total of 440.2 MMBOE. See “Oil and Natural Gas Reserves”.

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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. Resource plays generally exhibit lower production decline rates over the long term and a longer reserve life. Enerplus’ five resource play types include: (i) crude oil waterfloods, as Enerplus owns interests in 12 major and 15 minor waterflood properties throughout western Canada; (ii) shallow natural gas and coalbed methane in southeast and central Alberta and southwest Saskatchewan; (iii) Bakken oil in Montana; (iv) deep tight natural gas; and (v) oil sands in northeast Alberta. Additionally, Enerplus has interests in other conventional oil and natural gas properties. Each of these play types and property interests is described in detail under “--  Enerplus’ Play Types” below.

The following table outlines Enerplus’ average daily production in 2007 and its reserves as at December 31, 2007, in each case on a company interest basis, for each of Enerplus’ five resource plays and its other conventional oil and natural gas properties.

	Crude Oil Waterflood		Shallow Natural Gas and CBM		Deep Tight Natural Gas		Bakken Oil		Oil Sands		Other Conventional Oil and Gas		Total
2007 Average Daily Production
Crude oil (bbls/d)		14,424		-		-		9,916		-		10,167		34,506
Natural gas (Mcf//d)		10,260		87,949		43,814		7,300		-		112,931		262,254
NGLs (bbls/d)		442		38		1,470		-		-		2,154		4,104
Total (BOE/d)		16,576		14,696		8,772		11,132		-		31,143		82,319
Proved Plus Probable Reserves at December 31, 2007
Crude oil (Mbbls)		89,499		-		-		33,356		-		37,887		160,742
Natural gas (MMcf)		53,152		549,787		148,833		49,321		-		401,198		1,202,291
NGLs (Mbbls)		2,811		14		6,453		-		-		6,334		15,612
Bitumen (Mbbls)		-		-		-		-		63,498		-		63,498
Total Proved plus Probable Reserves (MBOE)		101,169		91,645		31,258		41,576		63,498		111,088		440,234

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Summary of Principal Production Locations

During the year ended December 31, 2007, on a BOE basis, 73% of Enerplus’ production was derived from Alberta, 14% from Montana, 8% from Saskatchewan, 3% from British Columbia and 2% from Manitoba. The following table describes the average daily production from Enerplus’ principal producing properties and their primary resource play type during the year ended December 31, 2007. All properties listed in the table (other than “Other”) are located in Alberta unless otherwise noted.

2007 Average Daily Production

		Product
		Crude Oil
Property	Primary Play Type	Heavy		Light and Medium		NGLs		Natural Gas		Total
		(bbls/d)		(bbls/d)		(bbls/d)		(Mcf/d)		(BOE/d)
Sleeping Giant, Montana, U.S.A.	Bakken Oil		-		9,849		-		7,808		11,150
Bantry	Shallow Gas		2,753		-		113		32,151		8,225
Joarcam	Waterflood		-		1,828		86		5,242		2,788
Pembina 5 Way	Waterflood		-		2,104		128		2,135		2,588
Giltedge	Waterflood		1,938		-		-		161		1,965
Pine Creek	Deep Tight Gas		-		14		456		8,942		1,961
Hanna Garden	Shallow Gas		-		-		3		11,453		1,911
Verger	Shallow Gas		-		-		-		11,209		1,868
Medicine Hat Glauconitic “C” Unit	Waterflood		1,708		-		-		499		1,791
Elmworth	Deep Tight Gas		-		-		438		8,105		1,789
Chinchaga	Conventional		-		-		33		9,481		1,613
Shackleton, Saskatchewan	Shallow Gas		-		-		-		8,721		1,453
Benjamin	Deep Tight Gas		-		-		7		8,044		1,348
Medicine Hat South	Shallow Gas		-		-		-		7,218		1,203
Valhalla	Conventional		-		248		83		5,086		1,178
Virden, Manitoba	Waterflood		-		1,119		-		-		1,119
Mitsue	Waterflood		-		802		139		1,039		1,114
Hayter	Conventional		1,008		-		2		78		1,023
Progress	Conventional		-		418		68		3,194		1,018
Shorncliff	Conventional		933		-		3		263		980
Other	N/A		632		9,152		2,545		131,425		34,234
TOTAL	N/A		8,972		25,534		4,104		262,254		82,319

Costs Incurred in 2007 and Summary of Capital Expenditures

In the financial year ended December 31, 2007, Enerplus made the following expenditures:

	Property Acquisition Costs
	Proved		Unproved		Exploration Costs		Development Costs
	($ in millions)
Canada	$	10.2	$	212.2	$	34.0	$	237.8
United States		61.0		0.9		13.8		91.5
Total	$	71.2	$	213.1	$	47.8	$	329.3

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The following table outlines the capital expenditures made by Enerplus in 2007 with respect to each of its five resource plays and its other conventional oil and natural gas properties.

	Crude Oil Waterflood		Shallow Natural Gas and CBM		Deep Tight Natural Gas		Bakken Oil		Oil Sands		Other Conventional Oil and Gas		Total
	(in $ millions)
Capital expenditures		54.2		39.3		34.7		106.2		38.9		113.9		387.2

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 2007, Enerplus participated in the drilling of 511 gross oil and natural gas wells (242.8 net wells) with 99% net well success rate, plus 18 gross (7.4 net) service wells and 5 gross (2.3 net) dry and abandoned wells. The majority of Enerplus’ drilling activity was in the shallow natural gas areas around 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 2007. 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, 2007, 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		122		40.1		3		2.1		35		20.8		3		2.2
Natural gas wells		318		168.1		30		9.5		-		-		-		-
Service wells		18		7.4		-		-		-		-		-		-
Dry and abandoned wells		3		1.1		1		0.5		-		-		1		0.7
Total		461		216.7		34		12.1		35		20.8		4		2.9

The following table summarizes the number and type of wells that Enerplus drilled, or participated in the drilling of, during 2007 in each of its five resource plays and its other conventional oil and natural gas properties, on a gross and net well basis.

	Crude Oil Waterflood		Shallow Natural Gas and CBM		Deep Tight Natural Gas		Bakken Oil		Oil Sands		Other Conventional Oil and Gas		Total
Gross wells		28		238		43		39		4		182		534
Net wells		19.6		155.5		6.3		23.7		0.6		46.8		252.5

Enerplus currently intends to focus its development activities in the Western Canadian Sedimentary Basin and on the Sleeping Giant property in Montana and North Dakota, although Enerplus also considers acquisitions (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.

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Oil and Natural Gas Wells and Unproved Properties

The following table summarizes, as at December 31, 2007, 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 (as defined in NI 51-101). 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 (thousand of acres)
	Oil				Natural Gas				Oil				Natural Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta		3,070		1,186.0		6,407		3,215.6		1,027		421.4		547		186.1		829.7		320.6
Saskatchewan		2,323		454.1		885		457.5		366		45.1		68		31.2		215.4		127.6
British Columbia		206		25.6		148		31.4		46		6.4		62		16.7		216.5		87.7
Manitoba		560		313.1		-		-		14		8.1		-		-		52.3		49.0
Montana		211		114.3		-		-		1		0.5		-		-		42.2		42.2
North Dakota		2		1.8		-		-		-		-		-		-		50.1		30.2
Utah		-		-		-		-		-		-		-		-		4.7		2.7
Oil Sands (Alberta)		18		2.9		-		-		-		-		-		-		70.2		51.6
Total		6,390		2,097.8		7,440		3,704.5		1,454		481.5		677		234.0		1,481.1		711.6

Enerplus expects its rights to explore, develop and exploit on approximately 104,000 net acres of unproved properties to expire prior to December 31, 2008 in the ordinary course. 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.

Enerplus’ Play Types

Outlined below is a description of each of Enerplus’ five resource play types and its other conventional oil and natural gas properties.

Crude Oil Waterfloods

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In a crude oil 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, 2007 and approximately 23% of Enerplus’ estimated Proved plus Probable Reserves as at December 31, 2007 were related to crude oil waterflood assets. Enerplus operates over 80% of its crude oil waterflood production, which is located throughout the Western Canadian Sedimentary Basin. In 2007, Enerplus’ five largest waterflood producing properties were Joarcam, Pembina 5 Way, Giltedge, the Medicine Hat Glauconitic “C” Unit and Virden, all of which are located in Alberta with the exception of Virden, which is in Manitoba. 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 $54 million on crude oil waterflood resource plays in 2007, drilling 20 new wells in Virden, Joarcam, Pembina and Silver Heights. Enerplus currently expects to increase its total spending on this play type in 2008 to approximately $105 million with plans for 49 new wells, increased optimization at its Cadogan property and two new surfactant (a form of enhanced oil recovery) pilot projects at Giltedge. Continued high oil prices and success in key development programs has laid the ground work for larger drilling programs at Pembina, Joarcam and Virden. Enerplus also intends to rebuild the Giltedge facility, after the previously announced fire in November 2007, and expects it to be back to full production by mid-2008.

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.

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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 18% of Enerplus’ average daily production volumes for the year ended December 31, 2007 and approximately 21% of Enerplus’ estimated Proved plus Probable Reserves as at December 31, 2007 were comprised of shallow natural gas and CBM. Approximately 67% of this production is operated by Enerplus. In 2007, Enerplus’ five largest shallow natural gas producing properties were the Bantry, Hanna Garden, Verger, Shackleton and Medicine Hat South properties, 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 reduced its shallow natural gas and CBM spending by approximately 60% in 2007 as compared to 2006 as weak natural gas prices and increasing costs eroded returns in this play type. Enerplus invested only $39 million on this resource play type in 2007 and concentrated spending on its most attractive shallow natural gas opportunities in the Bantry, Medicine Hat Sun Valley, Verger and Shackleton/Sceptre areas. Reserve additions were offset by technical disappointments at Hanna Garden, which negatively impacted overall finding and development costs for this play type. Enerplus’ drilling activity was significantly reduced with only 155 net wells drilled in 2007 compared to 249 in 2006.

Enerplus currently expects to increase its total spending on this play type in 2008 given improvements in costs and natural gas prices, the addition of Focus’ Shackleton property and the relatively limited impact from the proposed royalty changes in Alberta on its shallow natural gas program. Enerplus currently intends to drill approximately 371 net wells with total spending of approximately $128 million on its shallow natural gas and CBM resource plays in 2008. Enerplus anticipates that shallow natural gas activities will be focused at its properties in Shackleton, where it is infill drilling to increase well density from four to eight wells per section, and at Bantry, Medicine Hat and Fox Valley, where Enerplus is down spacing to 16 wells per section. Enerplus currently estimates that approximately 73% of its total conventional drilled wells in 2008 will be shallow natural gas wells.

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 crude oil (42o API) and some associated natural gas. As Enerplus’ single largest producing property, the Sleeping Giant project represented approximately 13% of Enerplus’ production in 2007 and 9% of Enerplus’ Proved plus Probable Reserves as at December 31, 2007. The property is predominantly operated by Enerplus.

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Enerplus’ capital investment activity in this play type remained high throughout 2007 with $106 million invested to complete the initial two wells per section drilling program across the core of the field, drill 25 third well per section wells, complete 23 well “refracs” (a “refrac” consists of the restimulation of a producing formation within an existing wellbore to enhance production and add new incremental reserves) and expand the resource outside of the core area. Overall results remained attractive on the third well per section drilling despite lower than anticipated initial production rates that averaged 200 BOE/d versus Enerplus’ original expectation of 300 BOE/d. Refracs continued to provide both incremental oil production and reserve recovery of approximately 50 BOE/d and 77,000 BOE, respectively. Enerplus’ expansion efforts to date outside the core Bakken area have been unsuccessful with two uneconomic Red River wells and uneconomic extension wells northwest and southeast of the core field area. In total Enerplus spent $14 million on expansion efforts including associated seismic costs. Enerplus continues to evaluate these early results and other potential outside the core Bakken area.

Enerplus’ 2007 development activities generated positive Proved plus Probable Reserve additions of approximately 10 MMBOE on this play type, offset by approximately 5 MMBOE of negative revisions. The additions were primarily associated with Enerplus’ third well per section and refrac program, while negative revisions were related to Enerplus’ extension areas and a change in recovery factor for solution gas. Since Enerplus’ acquisition of this property in 2005, it has added over 12 MMBOE of Proved plus Probable Reserves on the initial 30 MMBOE of Proved plus Probable Reserves originally acquired. In 2008 Enerplus plans to complement its ongoing capital program with a focused optimization effort and currently intends to spend approximately $47 million on this resource play. Optimization will include automating pump controls, managing fluid levels and improving field downtime. In 2008, Enerplus expects to complete the third well per section drilling program in the core areas of the field (approximately six wells) and continue the refrac program (estimated to consist of 24 refracs). Efforts to understand and evaluate enhanced oil recovery projects are also underway given Enerplus’ expectations as to the potential recovery beyond primary depletion on this resource play. Enerplus’ other activities in 2008 are expected to include determining the viability of a fourth well per section along the lease lines and further work in expanding areas outside the core Bakken play.

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Deep Tight Natural Gas

Enerplus’ deep tight natural gas resource play represented approximately 11% of Enerplus’ average daily production in 2007 and 7% of its Proved plus Probable Reserves as at December 31, 2007. Enerplus’ highest producing deep tight natural gas properties in 2007 were Pine Creek, Elmworth, and Benjamin, all of which are in Alberta. This play type includes mostly non-operated multi-zone deep tight natural gas plays such as Cardium, Nikannassin, Montney, Bluesky and Halfway zones as well as many others. In 2007, Enerplus completed its first significant operated development success with a $14 million deep natural gas drilling project at Ansell, where Enerplus added approximately 3.5 MMBOE of new Proved plus Probable Reserves by drilling four gross wells and also expanded natural gas gathering and compression facilities. At the date of this Annual Information Form, these wells are averaging gross production of approximately 2 MMcf/d with an average 45% working interest. The success at Ansell was partially offset by a 1.3 MMBOE negative Proved plus Probable Reserve revision at Enerplus’ non-operated Benjamin property associated with a Proved Undeveloped location, as the operator of that property elected not to drill the well due to lower natural gas prices and reallocation of capital to other projects. The majority of the $35 million Enerplus invested in 2007 continued to be in the non-operated areas of Deep Basin, Elmworth Wapiti, Pine Creek and Copton.

Through the Focus transaction Enerplus added the Tommy Lakes, British Columbia property, which Enerplus expects will be its largest operated deep tight natural gas field, producing approximately 6,000 BOE/d as of the date of this Annual Information Form. Enerplus currently anticipates overall spending in 2008 to increase to $53 million for this resource play type, mainly as a result of the addition of the Tommy Lakes property, with plans to spend approximately $20 million at Tommy Lakes and the remainder primarily in Ansell and the non-operated areas of Deep Basin, Elmworth, Wapiti and Copton.

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Oil Sands

Enerplus’ oil sands portfolio includes its operated SAGD Kirby Project, its non-operated SAGD and mining Joslyn Project and its joint venture with and equity ownership in Laricina. In addition to the acquisition cost of the Kirby Lease described below, Enerplus invested a total of $39 million in its oil sands portfolio in 2007 Enerplus believes that oil sands production will represent an increasing proportion of its production in the future. Enerplus 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.

Kirby Project:

Enerplus’ most significant oil sands activity in 2007 was the acquisition of the Kirby Lease for an aggregate purchase price of $203.1 million. The Kirby Project is a 100% working interest, Enerplus-operated SAGD project which Enerplus currently believes has potential production capacity, through staged development, of 30,000 to 40,000 bbls/d of bitumen. The Kirby Lease covers 43,360 gross acres (over 67 sections of land) in the Athabasca oil sands fairway near several other major SAGD development projects currently on production. While the Kirby Lease does not have current production or Proved or Probable Reserves, the independent GLJ Oil Sands Resources Report effective December 31, 2007 indicates a “best estimate” of contingent resources of 244 MMbbls of bitumen, as outlined in the table below. Enerplus believes that the Kirby Project is an attractive first operated project given the reservoir quality, apparent lack of thief zones, proximity to markets and infrastructure and potential expandability. Enerplus’ initial development plans currently include a 10,000 bbl/d SAGD project starting in 2012 with further expansion capability to a total of 30,000 to 40,000 bbls/d of gross bitumen production over time. Enerplus’ current expectations as to the key milestones associated with the development of the Kirby Lease are as follows:

• 2007/2008  - Winter drilling program, stakeholder consultation and work on regulatory applications

• Fall 2008  - Regulatory application filed

• Fall 2009  - Receipt of regulatory approval anticipated

• Late 2011  - First steam injection

• Mid-2012  - First production

• 2013  - Reaches production of 10,000 bbls/d

Enerplus’ capital spending on the Kirby Project in 2007 totalled $2 million. Enerplus began work on its first winter delineation drilling program at the Kirby Lease and drilled 58 new core holes and tested for water sources and disposal zones on the lease. Enerplus expects to use this new information in support of a 10,000 bbl/d SAGD project regulatory application in late fall of 2008. Enerplus anticipates that its original cost estimate of $365 million associated with the development of the 10,000 bbl/d project will be updated later in 2008 as work progresses on the regulatory application. Enerplus intends to spend approximately $50 million in 2008 on its core hole winter drilling program and the regulatory application.

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GLJ, a private independent petroleum consulting firm based in Calgary, Alberta, has evaluated, estimated and subsequently prepared the GLJ Oil Sands Resources Report, which includes an estimate of the contingent bitumen resources associated with the Kirby Lease, in accordance with the standards contained in the COGE Handbook. The GLJ Oil Sands Resources Report has provided the contingent resource estimates for the Kirby Lease on a bitumen basis rather than a synthetic crude oil basis as, at present, there are no definitive plans to provide an upgraded product.

The contingent resource estimate for the Kirby Lease set forth below is presented as the “best estimate” of the quantity that will actually be recovered, meaning that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate. 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.

	Best Estimate of Contingent Bitumen Resources
	(Mbbls)
Kirby Lease		244,374

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 Kirby Project as “reserves” consist of: current uncertainties around the specific scope and timing of the development of the Kirby Project; proposed reliance on technologies that have not yet been demonstrated to be commercially applicable in oil sands applications; lack of regulatory approvals for the Kirby Project; the uncertainty regarding marketing plans for production from the subject areas; and improved estimation of project costs. Enerplus currently believes that development of the Kirby Project will proceed as outlined above. 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  - Each of the Kirby Project and the Joslyn Project is in the early development stage and is subject to numerous risks.”

For additional information regarding the disclosure of contingent resources, see “Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information  - Disclosure of Contingent Resources”.

Joslyn Project:

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, as described under “--  Laricina” below. As a result, Enerplus now has a 15% working interest in the Joslyn Project.

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The Joslyn Lease currently has two key mining areas (designated as the North Mine and South Mine) and a SAGD area with expansion potential. 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 300 bbls/d on a gross basis (45 bbls/d net to Enerplus)) in 2004 and was designed to provide useful information for the future operations of the 10,000 bbl/d (1,500 bbl/d net to Enerplus) SAGD Phase II project, which continues to run behind expectations. Total has advised Enerplus that it does not currently expect to drill any new well pairs or achieve commercial production on the SAGD project until at least 2009, pending continued improvement in well performance. Gross production volumes at the end of 2007 from the SAGD project were approximately 2,400 bbls/d (360 bbls/d net to Enerplus). In light of the pre-commercial nature of this production, Enerplus has not included it in its reported production volumes. Enerplus expects the regulatory application for the North Mine to be approved in the second half of 2008. The extent of the South Mine development and the expansion potential for the SAGD project is currently being evaluated and Enerplus expects to finalize these plans with Total in 2008, along with an expanded joint operating agreement and Enerplus’ downstream marketing plans. Enerplus expects a regulatory application for the South Mine to be made once definitive lease development plans have been determined. As the lease development plans have not been finalized and significant engineering work is underway, Enerplus does not currently have estimates of the future capital requirements associated with the Joslyn Project. Enerplus expects to report capital spending estimates once the lease development plan is complete.

Enerplus continued to invest in the Joslyn Lease throughout 2007, spending $18 million on the SAGD project and $11 million on the Joslyn mining development. Enerplus’ activities included additional delineation spending, regulatory work, SAGD facility upgrades and other costs.

GLJ, a private independent petroleum consulting firm based in Calgary, Alberta, has prepared the GLJ Joslyn Reserves Report, in which Proved and Probable Reserves have been assigned to the current SAGD portion of the Joslyn Project, as described under “Oil and Natural Gas Reserves,” but no Proved or Probable Reserves have been assigned to the currently proposed mining development on the Joslyn Lease. Additionally, GLJ has evaluated, estimated and prepared the GLJ Oil Sands Resources Report, which includes an estimate of the contingent bitumen resources associated with certain mineable portions of Enerplus’ 15% interest in the Joslyn Project in accordance with the standards contained in the COGE Handbook. The GLJ Joslyn Reserves Report and the GLJ Oil Sands Resources Report, each effective December 31, 2007, resulted in additions of approximately 6.8 MMbbls of Proved plus Probable bitumen reserves and increased contingent resource estimates net to Enerplus. A key factor in the increased contingent resource estimates for the bitumen was a change from 12:1 total volume to bitumen in place ratio (“TV:BIP”) used in prior resource estimates to a 15:1 TV:BIP ratio for the December 31, 2007 estimates. The TV:BIP ratio measures the total volume of material (dirt, sand and bitumen) relative to the volume of bitumen in place; it considers how much dirt must be removed to access the bitumen deposit and the ore grade, or the richness of the deposit. Enerplus believes that the higher costs associated with mining at higher TV:BIP ratios is more than offset by higher commodity prices.

The operator of the Joslyn Project and its partners are considering an optimal development plan for the Joslyn Project which may result in a decision to mine certain areas of the lease currently designated for SAGD. GLJ has assigned approximately 423.3 MMbbls of Proved plus Probable gross lease reserves (63.5 MMbbls to Enerplus’ interest, which reserves are included in Enerplus’ reported reserves under “Oil and Natural Gas Reserves  - Summary of Joslyn Project Bitumen Reserves”) to the current SAGD portions of the Joslyn Lease. While Total is still determining the optimal lease development plan for the Joslyn Lease, should the mining area expand Enerplus would expect higher overall recoveries from the Joslyn Lease given the higher recovery factor for mining versus SAGD. Although the portions of the Joslyn Lease to which reserves have been assigned overlap with certain portions of the Joslyn Lease for which GLJ provided an estimate of contingent resource volumes, the contingent resource volumes presented in this Annual Information Form deduct the contingent resource volumes attributable to the overlapping sections, and as such the following estimates of contingent resources are incremental to the estimated reserves disclosed with respect to the Joslyn Project. See “Oil and Natural Gas Reserves  - Summary of Joslyn Project Bitumen Reserves”. The GLJ Oil Sands Resources Report has provided the contingent resource estimates on a bitumen basis rather than a synthetic crude oil basis as, at present, there are no definitive plans to provide an upgraded product. However, Total, as the operator of the Joslyn Project, continues to evaluate an upgrader solution for the Joslyn Project, which may or may not include Enerplus' share of production from the Joslyn Project.

Set forth below is a summary of the contingent resource estimates for certain mineable portions of the Joslyn Lease as a whole and for Enerplus’ 15% interest in the Joslyn Lease, as included in the GLJ Oil Sands Resources Report. The contingent resource estimates for the Joslyn Lease set forth below are presented as the “best estimate” of the quantity that will actually be recovered, meaning that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate. The contingent resource estimates for the mining portion of the Joslyn Lease use a 15:1 TV:BIP ratio at December 31, 2007 as compared to the 12:1 TV:BIP ratio used in connection with the previous disclosure of contingent resources at December 31, 2006. 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.

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	Best Estimate of Contingent Bitumen Resources
	Gross Lease		Enerplus Gross
	(MMbbls)
Joslyn Lease		2,040		306

The following table sets forth the estimated contingent resource volumes attributable to Enerplus’ 15% interest in the Joslyn Lease under two separate development scenarios: one being the development of the entire remainder of the Joslyn Lease on a mining basis with the current 10,000 bbl/d SAGD project being maintained with no future expansion, and the second being a smaller future mining development with expansion of the SAGD operations to a 25,000 bbl/d project. At this time Enerplus cannot predict whether one of these two scenarios, or an alternative scenario, will ultimately be the development plan approved for the Joslyn Project.

	Best Estimate of Contingent Bitumen Resources
Joslyn Lease Development Scenario	Gross Lease		Enerplus Gross
	(MMbbls)
Full Mine with 10,000 bbl/d SAGD Project		2,390		359
Smaller Mine with 25,000 bbl/d SAGD Project		1,680		252

Under the “Full Mine with 10,000 bbl/d SAGD Project” scenario, the gross SAGD-recoverable Proved plus Probable Reserves attributable to Enerplus’ 15% interest in the Joslyn Lease would decrease from the 63.5 MMbbls reported under “Oil and Natural Gas Reserves  - Summary of Joslyn Project Bitumen Reserves” to approximately 11.0 MMbbls, which generally corresponds (with certain adjustments) to the increase of the best estimate of Enerplus’ gross bitumen resources from 306 MMbbls in the GLJ Oil Sands Resources Report to the 359 MMbbls under the “Full Mine” scenario.

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; lack of regulatory approval for various aspects of the Joslyn Project; the uncertainty regarding marketing plans for production from the subject areas; and improved estimation of project costs. Based on current information and market conditions, Enerplus believes that development of the Joslyn Project will proceed as described in this Annual Information Form. However, there are a number of inherent risks and contingencies associated with such development, including the uncertainty regarding the SAGD expansion and the development of the mining portion of the Joslyn Lease, 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  - Each of the Kirby Project and the Joslyn Project is in the early development stage and is subject to numerous risks.”

For additional information regarding the disclosure of contingent resources, see “Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information  - Disclosure of Contingent Resources”.

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Laricina:

In 2005, Enerplus formed a joint venture with Laricina, a private oil sands company focused on SAGD development in the Athabasca oil sands fairway that is led by the former Chief Executive Officer of Deer Creek Energy Limited. As part of this joint venture, Enerplus swapped a 1% working interest in the Joslyn Lease for approximately 20% equity value in Laricina. Enerplus now estimates that it owns approximately 12% of the total outstanding equity of Laricina. Included in the sale was an area of mutual interest agreement which was designed to allow Enerplus and Laricina to jointly pursue additional in-situ oil sands ventures, which agreement has now expired. Enerplus has participated in four land acquisitions with Laricina, and in 2007 invested approximately $8 million in an effort to delineate the potential on these lands.

Other Conventional Oil and Gas 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 a diversified portfolio of both operated and non-operated oil and natural gas projects which are generally smaller in nature and consist of various reservoir types. Enerplus operates approximately 70% of these assets. Major conventional assets include the Chinchaga, Valhalla, Hayter, Progress and Shorncliff properties in Alberta. Average 2007 daily production from these other conventional oil and gas properties represented approximately 38% of Enerplus’ production. These other conventional oil and gas reserves accounted for approximately 25% of Enerplus’ estimated total Proved plus Probable Reserves as of December 31, 2007.

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.

In 2007, Enerplus’ capital investment was reduced in this play type by 19% year-over-year primarily due to lower capital spending in our non-operated properties and a shift to more spending in Enerplus’ Bakken oil play. Despite efforts to high-grade its capital program, Enerplus' 2007 activities did not result in the number of high impact wells that were experienced in 2006, and its activities at two main projects where it spent approximately $15 million (Kantah and Tatagwa) did not produce the results that Enerplus expected. In total, Enerplus spent $114 million on capital development activities in this play type in 2007.

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In 2008, Enerplus expects to spend approximately $142 million on a variety of oil and natural gas projects, both operated ($100 million) and non-operated ($42 million). Enerplus currently intends to spend just under $20 million on operated oil optimization activities and equipment upgrades at Bantry North and South and almost $20 million at its oil properties in southeast Saskatchewan, primarily on horizontal drilling in an attempt to extend the boundaries of those assets. Enerplus anticipates that the remainder of the operated capital will be spent on a variety of smaller prospects in Alberta and British Columbia.

Quarterly Production History

The following table sets forth Enerplus’ average daily production volumes, on a company interest basis, for each fiscal quarter in 2007 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 2007.

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Canada
Crude oil
Light and medium oil (bbls/d)		16,096		15,626		15,378		15,701		15,698
Heavy oil (bbls/d)		9,234		8,937		8,858		8,547		8,892
Total crude oil (bbls/d)		25,330		24,563		24,236		24,248		24,590
Natural gas liquids (bbls/d)		4,509		4,143		3,937		3,836		4,104
Total liquids (bbls/d)		29,839		28,706		28,173		28,084		28,694
Natural gas (Mcf/d)		266,050		254,122		241,196		245,219		251,561
Total Canada (BOE/d)		74,180		71,059		68,372		68,953		70,621
United States
Light and medium crude oil (bbls/d)		10,237		9,615		9,841		9,973		9,916
Natural gas (Mcf/d)		9,664		10,824		10,068		12,196		10,693
Total United States (BOE/d)		11,848		11,419		11,519		12,006		11,698
Total Enerplus
Crude oil
Light and medium oil (bbls/d)		26,333		25,241		25,219		25,674		25,614
Heavy oil (bbls/d)		9,234		8,937		8,858		8,547		8,892
Total crude oil (bbls/d)		35,567		34,178		34,077		34,221		34,506
Natural gas liquids (bbls/d)		4,509		4,143		3,937		3,836		4,104
Total liquids (bbls/d)		40,076		38,321		38,014		38,057		38,610
Natural gas (Mcf/d)		275,714		264,946		251,264		257,415		262,254
Total Enerplus (BOE/d)		86,028		82,478		79,891		80,959		82,319

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Quarterly Netback History

The following tables set forth Enerplus’ average netbacks received for each fiscal quarter in 2007 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 2007. 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, 2007
Light and Medium Crude Oil ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price(1)	$	60.06		$	66.52		$	72.98		$	77.07		$	69.14
Royalties		(8.78	)		(10.72	)		(11.25	)		(11.67	)		(10.60	)
Production costs(2)		(15.99	)		(17.51	)		(20.04	)		(18.00	)		(17.88	)
Netback	$	35.29		$	38.29		$	41.69		$	47.40		$	40.66
United States
Sales price(1)	$	62.99		$	67.94		$	77.49		$	80.16		$	72.17
Royalties(3)		(12.48	)		(13.60	)		(15.92	)		(16.73	)		(14.69	)
Production costs(2)		(2.24	)		(2.56	)		(2.94	)		(3.11	)		(2.71	)
Netback	$	48.27		$	51.78		$	58.63		$	60.32		$	54.77
Total Enerplus
Sales price(1)	$	61.19		$	67.06		$	74.74		$	78.27		$	70.31
Royalties(3)		(10.22	)		(11.82	)		(13.07	)		(13.63	)		(12.18	)
Production costs(2)		(10.65	)		(11.82	)		(13.37	)		(12.22	)		(12.01	)
Netback	$	40.32		$	43.42		$	48.30		$	52.42		$	46.12

	Year Ended December 31, 2007
Heavy Oil ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada/Total Enerplus
Sales price(1)	$	46.02		$	47.48		$	53.28		$	54.00		$	50.14
Royalties		(9.01	)		(9.22	)		(10.34	)		(10.69	)		(9.81	)
Production costs(2)		(11.24	)		(12.08	)		(15.03	)		(15.13	)		(13.35	)
Netback	$	25.77		$	26.18		$	27.91		$	28.18		$	26.98

	Year Ended December 31, 2007
Natural Gas Liquids ($ per bbl)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada/Total Enerplus
Sales price(1)	$	44.09		$	53.34		$	50.79		$	58.12		$	51.35
Royalties		(11.25	)		(13.56	)		(13.42	)		(15.94	)		(13.46	)
Production costs(2)		-			-			-			-			-
Netback	$	32.84		$	39.78		$	37.37		$	42.18		$	37.89

22

	Year Ended December 31, 2007
Natural Gas ($ per Mcf)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price(1)	$	7.21		$	7.03		$	5.58		$	5.91		$	6.45
Royalties		(1.42	)		(1.34	)		(1.05	)		(1.12	)		(1.24	)
Production costs(2)		(1.31	)		(1.55	)		(1.27	)		(1.02	)		(1.29	)
Netback	$	4.48		$	4.14		$	3.26		$	3.77		$	3.92
United States
Sales price(1)	$	7.29		$	7.37		$	5.67		$	5.98		$	6.55
Royalties(3)		(1.45	)		(1.45	)		(1.28	)		(1.53	)		(1.43	)
Production costs(2)		-			-			-			-			-
Netback	$	5.84		$	5.92		$	4.39		$	4.45		$	5.12
Total Enerplus
Sales price(1)	$	7.21		$	7.04		$	5.59		$	5.91		$	6.45
Royalties(3)		(1.42	)		(1.35	)		(1.06	)		(1.14	)		(1.25	)
Production costs(2)		(1.27	)		(1.48	)		(1.22	)		(0.97	)		(1.24	)
Netback	$	4.52		$	4.21		$	3.31		$	3.80		$	3.96

	Year Ended December 31, 2007
Total ($ per BOE)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total for Year
Canada
Sales price(1)	$	47.28		$	48.84		$	46.01		$	48.78		$	47.73
Royalties		(8.81	)		(9.11	)		(8.36	)		(8.85	)		(8.78	)
Production costs(2)		(9.58	)		(10.91	)		(10.95	)		(9.61	)		(10.25	)
Netback	$	28.89		$	28.82		$	26.70		$	30.32		$	28.70
United States
Sales price(1)	$	60.37		$	64.19		$	71.15		$	72.66		$	67.16
Royalties(3)		(11.96	)		(12.82	)		(14.71	)		(15.45	)		(13.76	)
Production costs(2)		(1.94	)		(2.15	)		(2.51	)		(2.58	)		(2.30	)
Netback	$	46.47		$	49.22		$	53.93		$	54.63		$	51.10
Total Enerplus
Sales price(1)	$	49.08		$	50.96		$	49.64		$	52.33		$	50.48
Royalties(3)		(9.12	)		(9.63	)		(9.28	)		(9.83	)		(9.49	)
Production costs(2)		(8.53	)		(9.69	)		(9.73	)		(8.57	)		(9.12	)
Netback	$	31.43		$	31.64		$	30.63		$	33.93		$	31.87

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.

23

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 cost formulas used by Alberta’s Energy Resources Conservation 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 $543 million on an undiscounted basis and $76 million discounted at 10%. The calculations of future net revenue under “Oil and Natural Gas Reserves” in this Annual Information Form have excluded approximately $292 million on an undiscounted basis and $49 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 $60.3 million on an undiscounted basis and $52.5 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, 2007. Under Enerplus’ current structure, taxable income of the Canadian Operating Subsidiaries is transferred through interest, royalty and other distribution payments to the Fund, which in turn, allocates all of its taxable income to its unitholders. Enerplus does not expect any material Canadian income tax liability to be incurred by the Fund or its Canadian Operating Subsidiaries prior to 2011. As described in further detail under “General Development of Enerplus Resources Fund  - Developments in the Past Three Years  - Changes to Taxation of 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 implemented the SIFT Tax which will generally tax income trusts at the same effective tax rates as Canadian corporations beginning in 2011.

United States

A total of $23.0 million of U.S. income related cash taxes were incurred with respect to U.S. operations during the year ended December 31, 2007. Enerplus’ U.S. operations are subject to income taxes payable on the taxable income determined under U.S. income tax rules and regulations. As funds are repatriated back to Canada, withholding taxes as required by U.S. tax law would become payable. As a result, Enerplus’ U.S. operations are expected to continue to incur U.S. income related cash taxes in the future.

For additional information, see Notes 1(h) and 11 to the Fund’s audited financial statements for the year ended December 31, 2007 and the information under the heading “Taxes” in the Fund’s management’s discussion and analysis for the year ended December 31, 2007.

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 $70.31/bbl for its light and medium crude oil, $50.14/bbl for its heavy crude oil and $51.35/bbl for its NGLs for the year ended December 31, 2007, compared to $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. Enerplus has a long-term transportation commitment to deliver 2,480 bbls/d of Canadian production on the Plains Marketing Canada Joarcam Pipeline.

24

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 at AECO and 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 2007, these aggregator contracts returned a price just slightly lower than the monthly Alberta spot market price.

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 holds multiple contracts of various terms greater than one year for transportation on the major gathering pipeline systems of those provinces. The contracts comprise approximately 104 MMcf/d on the TransCanada, NOVA Gas Transmission system in Alberta. Upon the completion of the Focus acquisition, Enerplus assumed natural gas term transportation contracts consisting of approximately 45 MMcf/d in British Columbia and approximately 60 MMcf/d in Saskatchewan.

Enerplus’ percentage of 2007 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 41% compared to 43% in 2006. The average price received by Enerplus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2007 was $6.45/Mcf compared to $6.81/Mcf in the year ended December 31, 2006. Within its sales portfolio of aggregator, downstream and spot natural gas, Enerplus sold approximately 40% of its natural gas based on the daily AECO market, 40% based on the monthly AECO market and 20% 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 12 to the Fund’s audited annual consolidated financial statements for the year ended December 31, 2007 and under the headings “Pricing” and “Price Risk Management” in the Fund’s management’s discussion and analysis for the year ended December 31, 2007, 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.

25

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, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 92% 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.

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

GLJ, 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 sections and tables summarize, as at December 31, 2007, Enerplus’ oil, NGLs, natural gas and bitumen 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 reserves attributable to Focus, which was acquired by Enerplus on February 13, 2008 as described under “General Development of Enerplus Resources Fund  - Events Subsequent to December 31, 2007  - Acquisition of Focus Energy Trust”. For information regarding Focus’ oil and gas reserves, as well as the combined oil and gas reserves of Enerplus and Focus effective as at December 31, 2007 (as if the transaction had taken place prior to such date), see Appendix “G”  - Information Regarding Focus Energy Trust. 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. 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 implemented the SIFT Tax which is designed to generally tax income trusts such as Enerplus at the same effective tax rates as Canadian corporations, effective for the 2011 tax year, and the after-tax estimates of the net present value of future net revenue from Enerplus’ reserves include the estimated impact of the SIFT Tax. Additionally, as the proposed amendments to the Province of Alberta’s royalty regime announced in October 2007 have not yet been passed into law and may be subject to further revision, the estimated net present value of future net revenues attributable to Enerplus’ reserves are based upon the existing Alberta royalty regime and do not give effect to the proposed changes. For additional information, see “General Development of Enerplus Resources Fund  - Developments in the Past Three Years”, “Operational Information  - Tax Horizon”, “Industry Conditions” and “Risk Factors” 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 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.

26

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 NSAI 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, as at December 31, 2007. Detailed separate summaries of the Sproule Report, the NSAI 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. For information on the combined oil and gas reserves of Enerplus and Focus effective as at December 31, 2007 (as if the transaction had taken place prior to that date), see Appendix “G”  - Information Regarding Focus Energy Trust.

Summary of Aggregate Oil and Gas Reserves

As of December 31, 2007

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		63,963		28,832		2,365		95,160		10,469		649,382		213,860
United States		21,672		-		-		21,672		74		28,527		26,501
Total		85,635		28,832		2,365		116,832		10,543		677,909		240,361
Proved Developed Non-Producing
Canada		190		-		-		190		510		14,911		3,185
United States		1,588		-		-		1,588		5		1,623		1,863
Total		1,778		-		-		1,778		515		16,534		5,048
Proved Undeveloped
Canada		3,233		2,383		6,203		11,819		694		164,829		39,984
United States		3,377		-		-		3,377		33		6,805		4,544
Total		6,610		2,383		6,203		15,196		727		171,634		44,528
Total Proved
Canada		67,386		31,215		8,568		107,169		11,673		829,122		257,029
United States		26,637		-		-		26,637		112		36,955		32,908
Total		94,023		31,215		8,568		133,806		11,785		866,077		289,937
Probable
Canada		17,837		10,948		54,930		83,715		3,797		308,276		138,891
United States		6,719		-		-		6,719		30		27,938		11,406
Total		24,556		10,948		54,930		90,434		3,827		336,214		150,297
Total Proved plus Probable
Canada		85,223		42,163		63,498		190,884		15,470		1,137,398		395,920
United States		33,356		-		-		33,356		142		64,893		44,314
Total		118,579		42,163		63,498		224,240		15,612		1,202,291		440,234

27

Summary of Aggregate Net Present Value

of Future Net Revenue Attributable to Oil and Gas Reserves

As of December 31, 2007

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%		Unit Value(1)
	(in $ millions)													($/BOE)
CONVENTIONAL OIL AND GAS RESERVES
Proved Developed Producing
Canada		7,365	4,669	3,514	2,869	2,451		6,359	4,204	3,248	2,698	2,333			19.80
United States		1,296	933	738	618	537		957	686	539	448	387			33.08
Total		8,661	5,602	4,252	3,487	2,988		7,316	4,890	3,787	3,146	2,720			21.29
Proved Developed Non-Producing
Canada		92	58	42	33	26		75	49	36	27	24			17.20
United States		95	69	53	43	36		57	42	31	26	20			34.11
Total		187	127	95	76	62		132	91	67	53	44			23.80
Proved Undeveloped
Canada		640	393	251	162	104		549	332	209	132	79			8.67
United States		187	119	83	61	47		121	74	50	35	26			21.04
Total		827	512	334	223	151		670	406	259	167	105			10.15
Total Proved
Canada		8,097	5,120	3,807	3,064	2,581		6,983	4,585	3,493	2,857	2,436			18.23
United States		1,578	1,121	874	722	620		1,135	802	620	509	433			31.44
Total Proved Conventional Reserves		9,675	6,241	4,681	3,786	3,201		8,118	5,387	4,113	3,366	2,869			19.78
Probable
Canada		3,195	1,452	857	582	430		2,446	1,133	681	472	353			12.25
United States		610	288	175	125	97		392	181	108	74	57			18.24
Total Probable Conventional Reserves		3,805	1,740	1,032	707	527		2,838	1,314	789	546	410			12.97
Total Proved Plus Probable Conventional Reserves		13,480	7,981	5,713	4,493	3,728		10,956	6,701	4,902	3,912	3,279			18.07
BITUMEN RESERVES
Proved Developed Producing		35	28	23	19	16		28	22	19	15	13			9.63
Proved Undeveloped		100	56	32	19	11		72	40	22	13	7			5.63
Total Proved		135	84	55	38	27		100	62	41	28	20			6.79
Probable		1,293	294	89	29	6		928	207	59	15	(1	)		1.84
Total Proved Plus Probable Bitumen Reserves		1,428	378	144	67	33		1,028	269	100	43	19			2.55
TOTAL CONVENTIONAL RESERVES AND BITUMEN RESERVES		14,908	8,359	5,857	4,560	3,761		11,984	6,970	5,002	3,955	3,298			15.72

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

28

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 NSAI Report.

Summary of Conventional Oil and Gas Reserves

As of December 31, 2007

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		63,963		63,260		58,177		28,832		28,792		24,261		649,382		627,730		525,807
United States		21,672		21,624		18,049		-		-		-		28,527		20,527		25,057
Total		85,635		84,884		76,226		28,832		28,792		24,261		677,909		648,257		550,864
Proved Developed Non-Producing
Canada		190		190		163		-		-		-		14,911		14,867		11,629
United States		1,588		1,588		1,330		-		-		-		1,623		1,107		1,445
Total		1,778		1,778		1,493		-		-		-		16,534		15,974		13,074
Proved Undeveloped
Canada		3,233		3,221		2,945		2,383		2,383		2,006		164,829		161,531		141,152
United States		3,377		3,377		2,840		-		-		-		6,805		3,042		6,321
Total		6,610		6,598		5,785		2,383		2,383		2,006		171,634		164,573		147,473
Total Proved Reserves
Canada		67,386		66,672		61,285		31,215		31,175		26,267		829,122		804,128		678,588
United States		26,637		26,588		22,220		-		-		-		36,955		24,676		32,823
Total		94,023		93,260		83,505		31,215		31,175		26,267		866,077		828,804		711,411
Probable Reserves
Canada		17,837		17,645		15,903		10,948		10,924		9,093		308,276		301,400		253,407
United States		6,719		6,703		5,608		-		-		-		27,938		24,551		23,790
Total		24,556		24,348		21,511		10,948		10,924		9,093		336,214		325,951		277,197
Total Proved Plus Probable Reserves
Canada		85,223		84,317		77,188		42,163		42,099		35,360		1,137,398		1,105,528		931,995
United States		33,356		33,291		27,828		-		-		-		64,893		49,227		56,614
Total		118,579		117,608		105,016		42,163		42,099		35,360		1,202,291		1,154,755		988,609

(continues on next page)

29

(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		10,469		10,279		7,378		211,495		206,953		177,450
United States		74		-		74		26,501		25,045		22,300
Total		10,543		10,279		7,452		237,996		231,998		199,750
Proved Developed Non-Producing
Canada		510		509		359		3,185		3,177		2,461
United States		5		-		5		1,863		1,772		1,576
Total		515		509		364		5,048		4,949		4,037
Proved Undeveloped
Canada		694		693		485		33,781		33,219		28,961
United States		33		-		33		4,544		3,884		3,926
Total		727		693		518		38,325		37,103		32,887
Total Proved Reserves
Canada		11,673		11,481		8,222		248,461		243,349		208,872
United States		112		-		112		32,908		30,701		27,802
Total		11,785		11,481		8,334		281,369		274,050		236,674
Probable Reserves
Canada		3,797		3,730		2,700		83,961		82,532		69,931
United States		30		-		30		11,406		10,795		9,604
Total		3,827		3,730		2,730		95,367		93,327		79,535
Total Proved Plus Probable Reserves
Canada		15,470		15,211		10,922		332,422		325,881		278,803
United States		142		-		142		44,314		41,496		37,406
Total		15,612		15,211		11,064		376,736		367,377		316,209

30

Summary of Net Present Value of Future Net Revenue

Attributable to Conventional Oil and Gas Reserves

As of December 31, 2007

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%	Unit Value(1)
	(in $ millions)												($/BOE)
Proved developed producing
Canada		7,365	4,669	3,514	2,869	2,451		6,359	4,204	3,248	2,698	2,333	$	19.80
United States		1,296	933	738	618	537		957	686	539	448	387	$	33.08
Total		8,661	5,602	4,252	3,487	2,988		7,316	4,890	3,787	3,146	2,720	$	21.29
Proved developed non-producing
Canada		92	58	42	33	26		75	49	36	27	24	$	17.20
United States		95	69	53	43	36		57	42	31	26	20	$	34.11
Total		187	127	95	76	62		132	91	67	53	44	$	23.80
Proved undeveloped
Canada		640	393	251	162	104		549	332	209	132	79	$	8.67
United States		187	119	83	61	47		121	74	50	35	26	$	21.14
Total		827	512	334	223	151		670	406	259	167	105	$	10.16
Total Proved
Canada		8,097	5,120	3,807	3,064	2,581		6,983	4,585	3,493	2,857	2,436	$	18.23
United States		1,578	1,121	874	722	620		1,135	802	620	509	433	$	31.44
Total		9,675	6,241	4,681	3,786	3,201		8,118	5,387	4,113	3,366	2,869	$	19.78
Probable
Canada		3,195	1,452	857	582	430		2,446	1,133	681	472	353	$	12.25
United States		610	288	175	125	97		392	181	108	74	57	$	18.22
Total		3,805	1,740	1,032	707	527		2,838	1,314	789	546	410	$	12.98
Proved Plus Probable
Canada		11,292	6,572	4,664	3,646	3,011		9,429	5,718	4,174	3,329	2,789	$	16.73
United States		2,188	1,409	1,049	847	717		1,527	983	728	583	490	$	28.04
Total		13,480	7,981	5,713	4,493	3,728		10,956	6,701	4,902	3,912	3,279	$	18.07

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

31

Summary of Conventional Oil and Gas Reserves

As of December 31, 2007

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		64,437		63,733		58,632		28,740		28,700		24,190		645,175		623,551		522,168
United States		21,971		21,921		18,297		-		-		-		28,930		20,931		25,391
Total		86,408		85,654		76,929		28,740		28,700		24,190		674,105		644,482		547,559
Proved Developed Non-Producing
Canada		190		190		163		-		-		-		14,755		14,710		11,486
United States		1,588		1,588		1,331		-		-		-		1,626		1,109		1,448
Total		1,778		1,778		1,494		-		-		-		16,381		15,819		12,934
Proved Undeveloped
Canada		3,233		3,223		2,946		2,376		2,376		1,999		164,244		160,956		140,803
United States		3,400		3,400		2,859		-		-		-		6,779		3,071		6,290
Total		6,633		6,623		5,805		2,376		2,376		1,999		171,023		164,027		147,093
Total Proved Reserves
Canada		67,860		67,146		61,741		31,116		31,076		26,189		824,174		799,217		674,457
United States		26,959		26,909		22,487		-		-		-		37,335		25,111		33,129
Total		94,819		94,055		84,228		31,116		31,076		26,189		861,509		824,328		707,586
Probable Reserves
Canada		18,071		17,879		16,130		10,913		10,889		9,065		305,547		298,707		251,087
United States		6,652		6,636		5,553		-		-		-		27,634		24,759		23,452
Total		24,723		24,515		21,683		10,913		10,889		9,065		333,181		323,466		274,539
Total Proved Plus Probable Reserves
Canada		85,931		85,025		77,871		42,029		41,965		35,254		1,129,721		1,097,924		925,544
United States		33,611		33,545		28,040		-		-		-		64,969		49,870		56,581
Total		119,542		118,570		105,911		42,029		41,965		35,254		1,194,690		1,147,794		982,125

(continues on next page)

32

(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		10,463		10,273		7,371		211,169		206,631		177,221
United States		74		-		74		26,867		25,410		22,603
Total		10,537		10,273		7,445		238,036		232,041		199,824
Proved Developed Non-Producing
Canada		511		509		359		3,160		3,151		2,436
United States		5		-		5		1,864		1,773		1,578
Total		516		509		364		5,024		4,924		4,014
Proved Undeveloped
Canada		694		693		485		33,677		33,118		28,897
United States		32		-		32		4,562		3,911		3,939
Total		726		693		517		38,239		37,029		32,836
Total Proved Reserves
Canada		11,668		11,475		8,215		248,006		242,900		208,554
United States		111		-		111		33,293		31,094		28,120
Total		11,779		11,475		8,326		281,299		273,994		236,674
Probable Reserves
Canada		3,786		3,720		2,691		83,695		82,272		69,735
United States		26		-		26		11,283		10,763		9,487
Total		3,812		3,720		2,717		94,978		93,035		79,222
Total Proved Plus Probable Reserves
Canada		15,454		15,195		10,906		331,701		325,172		278,289
United States		137		-		137		44,576		41,857		37,607
Total		15,591		15,195		11,043		376,277		367,029		315,896

33

Summary of Net Present Value of Future Net Revenue

Attributable to Conventional Oil and Gas Reserves

As of December 31, 2007

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%	Unit Value(1)
	(in $ millions)												($/BOE)
Proved Developed Producing
Canada		6,515	4,356	3,351	2,764	2,374		5,571	3,886	3,072	2,582	2,248	$	18.91
United States		1,370	1,001	798	670	583		1,038	762	608	512	447	$	35.29
Total		7,885	5,357	4,149	3,434	2,957		6,609	4,648	3,680	3,094	2,695	$	20.76
Proved Developed Non-Producing
Canada		77	52	39	31	25		61	43	33	26	22	$	15.84
United States		102	75	59	49	41		64	47	38	31	25	$	37.65
Total		179	127	98	80	66		125	90	71	57	47	$	24.40
Proved Undeveloped
Canada		471	286	177	108	62		398	242	149	89	49	$	6.13
United States		191	126	90	68	54		134	88	63	48	38	$	22.85
Total		662	412	267	176	116		532	330	212	137	87	$	8.13
Total Proved
Canada		7,063	4,694	3,567	2,903	2,461		6,030	4,171	3,254	2,697	2,319	$	17.10
United States		1,663	1,202	947	787	678		1,236	897	709	591	510	$	33.68
Total		8,726	5,896	4,514	3,690	3,139		7,266	5,068	3,963	3,288	2,829	$	19.07
Probable
Canada		2,361	1,190	745	523	395		1,726	892	572	411	316	$	10.68
United States		495	253	162	119	94		323	161	101	72	56	$	17.08
Total		2,856	1,443	907	642	489		2,049	1,053	673	483	372	$	11.45
Proved Plus Probable
Canada		9,424	5,884	4,312	3,426	2,856		7,756	5,063	3,826	3,108	2,635	$	15.49
United States		2,158	1,455	1,109	906	772		1,559	1,058	810	663	566	$	29.49
Total		11,582	7,339	5,421	4,332	3,628		9,315	6,121	4,636	3,771	3,201	$	17.16

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

34

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(1)			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)
2008		89.61			88.17			54.67			75.83			6.51			7.56			52.29			65.72			90.30			2.0			1.00
2009		86.01			84.54			52.42			72.71			7.22			8.27			50.14			63.01			86.58			2.0			1.00
2010		84.65			83.16			51.56			71.52			7.69			8.74			49.32			61.98			85.17			2.0			1.00
2011		82.77			81.26			50.38			69.89			7.70			8.75			48.20			60.57			83.23			2.0			1.00
2012		82.26			80.73			50.05			69.43			7.61			8.66			47.88			60.17			82.68			2.0			1.00
Thereafter			(2)			(2)			(2)			(2)			(2)		+2.0	%			(2)			(2)			(2)			(2)		1.00

Notes:

(1) Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

(2) Escalation varies after 2012.

In 2007, Enerplus received a weighted average price (net of transportation costs but before hedging) of $50.14/bbl for heavy crude oil, $70.31/bbl for light and medium crude oil, $51.35/bbl for NGLs and $6.45/Mcf for natural gas.

Constant Prices and Costs

The constant price and cost case assumes the continuance of product prices at December 31, 2007 and operating costs projected for 2008, 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, 2007 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(1)

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

96.00

93.44

41.70

72.58

6.52

6.80

61.75

81.79

95.59

-

1.009

Notes:

(1) Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

Undiscounted Future Net Revenue by Reserves Category

The undiscounted total future net revenue by reserves category as of December 31, 2007, using 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)
Proved Reserves
Canada		15,751		2,236		4,773		459		186		8,097		1,114		6,983
United States		2,554		510		380		62		24		1,578		443		1,135
Total		18,305		2,746		5,153		521		210		9,675		1,557		8,118
Proved Plus Probable Reserves
Canada		21,780		3,154		6,604		515		215		11,292		1,863		9,429
United States		3,562		721		562		62		29		2,188		661		1,527
Total		25,342		3,875		7,166		577		244		13,480		2,524		10,956

35

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, 2007, using forecast prices and costs and discounted at 10% per year, is set forth below:

Reserves Category	Production Group	Net Present Value of Future Net Revenue Before Income Taxes (Discounted at 10%/year)		Unit Value(3)
		(in $ millions)		($/Bbl / $/Mcf)
Canada
Proved Reserves	Light and Medium Crude Oil(1)		1,501		24.49
	Heavy Oil(1)		559		21.28
	Natural Gas(2)		1,747		2.80
Proved Plus Probable Reserves	Light and Medium Crude Oil(1)		1,800		23.32
	Heavy Oil(1)		678		19.17
	Natural Gas(2)		2,186		2.55
United States
Proved Reserves	Light and Medium Crude Oil(1)		824		37.08
	Heavy Oil(1)		-		-
	Natural Gas(2)		50		4.09
Proved Plus Probable Reserves	Light and Medium Crude Oil(1)		988		35.50
	Heavy Oil(1)		-		-
	Natural Gas(2)		61		3.92

Notes:

(1) Including net present value of solution gas and other by-products.

(2) Including net present value of by-products, but excluding solution gas and by-products from oil wells.

(3) Calculated using net oil or net gas reserves and forecast price and cost assumptions.

36

Estimated Production for Gross Reserves Estimates

The volume of production estimated for 2008 in preparing the estimates of gross Proved Reserves and gross Probable Reserves is set forth below. Canadian production has been estimated by Sproule and U.S. production has been estimated by NSAI.

Gross Proved Reserves

Canada

United States

Product Type

Estimated 2008 Aggregate Production

Estimated 2008 Average Daily Production

Estimated 2008 Aggregate Production

Estimated 2008 Average Daily Production

Crude Oil

Light and Medium Crude Oil

5,433

Mbbls

14,845

bbls/d

3,357

Mbbls

9,171

bbls/d

Heavy Oil

3,045

Mbbls

8,319

bbls/d

-

Mbbls

-

bbl/d

Total Crude Oil

8,478

Mbbls

23,164

bbls/d

3,357

Mbbls

9,171

bbls/d

Natural Gas Liquids

1,354

Mbbls

3,698

bbls/d

-

Mbbls

-

bbls/d

Total Liquids

9,832

Mbbls

26,862

bbls/d

3,357

Mbbls

9,171

bbls/d

Natural Gas

81,067

MMcf

221,495

Mcf/d

2,700

MMcf

7,378

Mcf/d

Total

23,343

MBOE

63,778

BOE/d

3,807

MBOE

10,401

BOE/d

Gross Probable Reserves

Canada

United States

Product Type

Estimated 2008 Aggregate Production

Estimated 2008 Average Daily Production

Estimated 2008 Aggregate Production

Estimated 2008 Average Daily Production

Crude Oil

Light and Medium Crude Oil

262

Mbbls

716

bbls/d

204

Mbbls

557

bbls/d

Heavy Oil

93

Mbbls

254

bbls/d

-

Mbbls

-

bbl/d

Total Crude Oil

355

Mbbls

970

bbls/d

204

Mbbls

557

bbls/d

Natural Gas Liquids

92

Mbbls

251

bbls/d

-

Mbbl

-

bbls/d

Total Liquids

447

Mbbls

1,221

bbls/d

204

Mbbls

557

bbls/d

Natural Gas

3,999

MMcf

10,926

Mcf/d

627

MMcf

1,713

Mcf/d

Total

1,113

MBOE

3,042

BOE/d

308

MBOE

842

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”):

	CANADA								UNITED STATES
	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)
2008		174		167		201		193		62		59		62		59
2009		115		100		132		114		-		-		-		-
2010		67		53		72		57		-		-		-		-
2011		42		30		44		32		-		-		-		-
2012		23		15		26		17		-		-		-		-
Remainder		38		18		40		19		-		-		-		-
Total		459		383		515		432		62		59		62		59

37

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, 2007, including certain assumptions relating to the determination of those reserves and values, as contained in the GLJ Reserves Report. Although the portions of the Joslyn Lease to which reserves have been assigned overlap with certain portions of the Joslyn Lease for which GLJ provided a contingent resource estimate, the contingent resource estimates presented in this Annual Information Form deduct the contingent resource volumes attributable to the overlapping sections, and as such the following estimated reserves are incremental to the estimated contingent resources disclosed with respect to the Joslyn Project. If it is determined that the Joslyn Lease development will proceed by way of a full mining development with no expansion of the current 10,000 bbl/d SAGD project, the gross SAGD-recoverable Proved plus Probable Reserves attributable to Enerplus’ 15% interest in the Joslyn Lease would be reduced to approximately 11.0 MMbbls. See “Operational Information  - Enerplus’ Play Types  - Oil Sands  - Joslyn Project”.

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, 2007

Forecast Prices and Costs

					NET PRESENT VALUE OF FUTURE NET REVENUE
	BITUMEN RESERVES				Before Deducting Income Taxes, Discontinued at (%/Year)						After Deducting Income Taxes, Discontinued at (%/Year)
RESERVES CATEGORY	Gross		Net			0%	5%	10%	15%	20%		0%	5%	10%	15%	20%		Unit Value(1)
	(Mbbls)		(Mbbls)		(in $ millions)													($/bbl)
Proved Developed Producing		2,365		2,341		35	28	23	19	16		28	22	19	15	13			9.63
Proved Undeveloped		6,203		5,756		100	56	32	19	11		72	40	22	13	7			5.63
Total Proved		8,568		8,097		135	84	55	38	27		100	62	41	28	20			6.79
Probable		54,930		48,372		1,293	294	89	29	6		928	207	59	15	(1	)		1.84
Total Proved Plus Probable		63,498		56,469		1,428	378	144	67	33		1,028	269	100	43	19			2.55

Constant Prices and Costs

					NET PRESENT VALUE OF FUTURE NET REVENUE
	BITUMEN RESERVES				Before Deducting Income Taxes, Discontinued at (%/Year)											After Deducting Income Taxes, Discontinued at (%/Year)
RESERVES CATEGORY	Gross		Net		0%		5%		10%		15%		20%			0%		5%		10%		15%			20%			Unit Value(1)
	(Mbbls)		(Mbbls)		(in $ millions)																							($/bbl)
Proved Developed Producing		2,365		2,341		24		19		15		12		11			19		15		13		11			9			6.55
Proved Undeveloped		6,203		6,083		70		38		21		12		6			50		27		14		7			3			3.49
Total Proved		8,568		8,424		94		57		36		24		17			69		42		27		18			12			4.34
Probable		54,930		49,060		547		134		38		7		(7	)		394		92		22		(1	)		(10	)		0.77
Total Proved Plus Probable		63,498		57,484		641		191		74		31		10			463		134		49		17			2			1.29

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

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$1.00 and the price and inflation rate forecasts set forth below supplied by Sproule as at December 31, 2007 (but utilized by GLJ for internal consistency in Enerplus’ reserves reporting). The forecast net prices for bitumen produced from the Joslyn Project are calculated by subtracting blending costs, transportation and quality differentials from the forecast prices for Hardisty Lloyd Blend crude oil for the relevant periods. The forecast net prices for bitumen produced from the Joslyn Project assume the sale of a bitumen-diluent blended product.

38

	CRUDE OIL												NATURAL GAS
Year	WTI Cushing Oklahoma			Edmonton Par Price 40°API(1)			Lloyd Blend 22.3°API			Joslyn Bitumen(3)			30 day spot @ AECO			Inflation Rate
	($US/bbl)			($Cdn/bbl)			($Cdn/bbl)			($Cdn/bbl)			($Cdn/mmbtu)			(%)
2008		89.61			88.17			61.72			34.17			6.51			2.0
2009		86.01			84.54			59.18			36.46			7.22			2.0
2010		84.65			83.16			58.21			37.54			7.69			2.0
2011		82.77			81.26			56.88			38.33			7.70			2.0
2012		82.26			80.73			56.51			38.03			7.61			2.0
Thereafter			(2)			(2)			(2)			(2)			(2)			(2)

Notes:

(1) Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

(2) Escalation varies after 2012.

(3) The price for bitumen is derived by GLJ from Sproule’s forecasts of various stream prices.

Constant Prices and Costs

The constant price and cost case assumes the continuance of product prices at December 31, 2007 and operating costs projected for 2008, and the continuance of current laws and regulations. The constant bitumen price was based on December 31, 2007 posted reference prices and average year differentials, according to the 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$1.009 and the following prices in effect as at December 31, 2007:

	CRUDE OIL						NATURAL GAS
	WTI Cushing Oklahoma		Edmonton Par Price 40°API(1)		Joslyn Bitumen(2)		30 day spot @ AECO
	($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/mmbtu)
Constant		96.00		93.44		31.05		6.52

Notes:

(1) Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

(2) The price for bitumen is derived by GLJ from Sproule’s forecasts of various stream prices.

Undiscounted Future Net Revenue by Reserves Category

The undiscounted total future net revenue by reserves category as of December 31, 2007, using 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)
Proved Reserves		363		22		176		29		1		135		35		100
Probable Reserves		3,510		430		1,390		391		6		1,293		365		928
Total Proved Plus Probable Reserves		3,873		452		1,566		420		7		1,428		400		1,028

39

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, 2007, using forecast prices and costs and discounted at 10% per year, is set forth below:

Reserves Category	Production Group	Net Present Value of Future Net Revenue Before Income Taxes (Discounted at 10%/year)		Unit Value(1)
		(in $ millions)		($ / bbl)
Proved Reserves	Bitumen		55		6.79
Probable Reserves	Bitumen		89		1.84
Total Proved Plus Probable Reserves	Bitumen		144		2.55

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

Estimated Production for Estimates of Future Net Revenue

The volume of gross production from the Proved plus Probable Reserves in 2008 estimated by GLJ in preparing the estimated net present values of future net revenue is as follows:

Product Type	Estimated 2008 Aggregate Production	Estimated 2008 Average Daily Production
Bitumen	241 Mbbls	659 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”):

	Proved Reserves				Proved Plus Probable Reserves
Year	Undiscounted		Discounted at 10%/year		Undiscounted		Discounted at 10%/year
	(in $ millions)
2008		4		4		4		4
2009		7		6		22		19
2010		1		1		34		27
2011		-		-		10		7
2012		-		-		-		-
Remainder		17		7		350		40
Total		29		18		420		97

40

Reconciliation of Reserves

The following tables reconcile Enerplus’ oil and natural gas reserves (on both a company interest and a gross reserves basis) from December 31, 2006 to December 31, 2007, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

Reconciliation of Company Interest Reserves

CANADA	Light & Medium 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, 2006		70,504			16,872			87,376			31,153			8,912		40,065			8,730			47,998		56,728
Acquisitions		2			-			2			-			-		-			-			-		-
Divestments		-			-			-			-			-		-			-			-		-
Discoveries		251			63			314			-			-		-			-			-		-
Extensions and Improved Recovery		1,810			654			2,464			1,870			1,301		3,171			-			4,064		4,064
Economic Factors		1,581			343			1,924			548			338		886			-			-		-
Technical Revisions		(986	)		(95	)		(1,081	)		844			397		1,241			(162	)		2,868		2,706
Production		(5,776	)		-			(5,776	)		(3,200	)		-		(3,200	)		-			-		-
December 31, 2007		67,386			17,837			85,223			31,215			10,948		42,163			8,568			54,930		63,498

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, 2006		12,690			3,777			16,467			905,261			306,804			1,212,065			273,954			128,693			402,647
Acquisitions		4			-			4			3,496			7,532			11,028			588			1,256			1,844
Divestments		-			-			-			(2,814	)		(325	)		(3,139	)		(469	)		(54	)		(523	)
Discoveries		5			1			6			178			45			223			285			72			357
Extensions and Improved Recovery		571			188			759			30,412			10,022			40,434			9,319			7,878			17,197
Economic Factors		114			20			134			5,527			1,156			6,683			3,164			894			4,058
Technical Revisions		(214	)		(189	)		(403	)		(21,118	)		(16,958	)		(38,076	)		(4,036	)		152			(3,884	)
Production		(1,497	)		-			(1,497	)		(91,820	)		-			(91,820	)		(25,776	)		-			(25,776	)
December 31, 2007		11,673			3,797			15,470			829,122			308,276			1,137,398			257,029			138,891			395,920

UNITED STATES	Light & Medium 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, 2006		23,391			8,637			32,028			-		-		-		-		-		-
Acquisitions		-			-			-			-		-		-		-		-		-
Divestments		-			-			-			-		-		-		-		-		-
Discoveries		-			-			-			-		-		-		-		-		-
Extensions and Improved Recovery		6,838			1,394			8,232			-		-		-		-		-		-
Economic Factors		-			-			-			-		-		-		-		-		-
Technical Revisions		15			(3,312	)		(3,297	)		-		-		-		-		-		-
Production		(3,607	)		-			(3,607	)		-		-		-		-		-		-
December 31, 2007		26,637			6,719			33,356			-		-		-		-		-		-

(continues on next page)

41

(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, 2006		-			-		-			14,800			37,221			52,021			25,858			14,840			40,698
Acquisitions		124			30		154			13,311			3,340			16,651			2,343			586			2,929
Divestments		-			-		-			-			-			-			-			-			-
Discoveries		-			-		-			-			-			-			-			-			-
Extensions and Improved Recovery		-			-		-			5,621			5,143			10,764			7,775			2,251			10,026
Economic Factors		-			-		-			-			-			-			-			-			-
Technical Revisions		-			-		-			7,126			(17,766	)		(10,640	)		1,202			(6,271	)		(5,069	)
Production		(12	)		-		(12	)		(3,903	)		-			(3,903	)		(4,270	)		-			(4,270	)
December 31, 2007		112			30		142			36,955			27,938			64,893			32,908			11,406			44,314

TOTAL ENERPLUS	Light & Medium 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, 2006		93,895			25,509			119,404			31,153			8,912		40,065			8,730			47,998		56,728
Acquisitions		2			-			2			-			-		-			-			-		-
Divestments		-			-			-			-			-		-			-			-		-
Discoveries		251			63			314			-			-		-			-			-		-
Extensions and Improved Recovery		8,648			2,048			10,696			1,870			1,301		3,171			-			4,064		4,064
Economic Factors		1,581			343			1,924			548			338		886			-			-		-
Technical Revisions		(971	)		(3,407	)		(4,378	)		844			397		1,241			(162	)		2,868		2,706
Production		(9,383	)		-			(9,383	)		(3,200	)		-		(3,200	)		-			-		-
December 31, 2007		94,023			24,556			118,579			31,215			10,948		42,163			8,568			54,930		63,498

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, 2006		12,690			3,777			16,467			920,061			344,025			1,264,086			299,812			143,533			443,345
Acquisitions		128			30			158			16,807			10,872			27,679			2,931			1,842			4,773
Divestments		-			-			-			(2,814	)		(325	)		(3,139	)		(469	)		(54	)		(523	)
Discoveries		5			1			6			178			45			223			285			72			357
Extensions and Improved Recovery		571			188			759			36,033			15,165			51,198			17,094			10,129			27,223
Economic Factors		114			20			134			5,527			1,156			6,683			3,164			894			4,058
Technical Revisions		(214	)		(189	)		(403	)		(13,992	)		(34,724	)		(48,716	)		(2,834	)		(6,119	)		(8,953	)
Production		(1,509	)		-			(1,509	)		(95,723	)		-			(95,723	)		(30,046	)		-			(30,046	)
December 31, 2007		11,785			3,827			15,612			866,077			336,214			1,202,291			289,937			150,297			440,234

42

Reconciliation of Gross Reserves

CANADA	Light & Medium 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, 2006		69,718			16,690			86,408			31,130			8,903		40,033			8,730			47,998		56,728
Acquisitions		2			-			2			-			-		-			-			-		-
Divestments		-			-			-			-			-		-			-			-		-
Discoveries		251			63			314			-			-		-			-			-		-
Extensions and Improved Recovery		1,795			652			2,447			1,870			1,301		3,171			-			4,064		4,064
Economic Factors		1,581			343			1,924			548			337		885			-			-		-
Technical Revisions		(997	)		(103	)		(1,100	)		797			383		1,180			(162	)		2,868		2,706
Production		(5,678	)		-			(5,678	)		(3,170	)		-		(3,170	)		-			-		-
December 31, 2007		66,672			17,645			84,317			31,175			10,924		42,099			8,568			54,930		63,498

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, 2006		12,481			3,708			16,189			877,780			299,699			1,177,479			268,356			127,249			395,605
Acquisitions		4			-			4			3,489			7,530			11,019			587			1,255			1,842
Divestments		-			-			-			(2,586	)		(252	)		(2,838	)		(431	)		(42	)		(473	)
Discoveries		1			(1	)		-			95			14			109			267			65			332
Extensions and Improved Recovery		558			179			737			29,597			9,588			39,185			9,156			7,794			16,950
Economic Factors		113			20			133			5,148			1,079			6,227			3,100			880			3,980
Technical Revisions		(209	)		(176	)		(385	)		(21,419	)		(16,258	)		(37,677	)		(4,140	)		261			(3,879	)
Production		(1,467	)		-			(1,467	)		(87,976	)		-			(87,976	)		(24,978	)		-			(24,978	)
December 31, 2007		11,481			3,730			15,211			804,128			301,400			1,105,528			251,917			137,462			389,379

UNITED STATES	Light & Medium 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, 2006		23,391			8,637			32,028			-		-		-		-		-		-
Acquisitions		-			-			-			-		-		-		-		-		-
Divestments		-			-			-			-		-		-		-		-		-
Discoveries		-			-			-			-		-		-		-		-		-
Extensions and Improved Recovery		6,838			1,394			8,232			-		-		-		-		-		-
Economic Factors		-			-			-			-		-		-		-		-		-
Technical Revisions		(57	)		(3,328	)		(3,385	)		-		-		-		-		-		-
Production		(3,584	)		-			(3,584	)		-		-		-		-		-		-
December 31, 2007		26,588			6,703			33,291			-		-		-		-		-		-

(continues on next page)

43

(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, 2006		-		-		-		14,800			37,221			52,021			25,858			14,840			40,698
Acquisitions		-		-		-		-			-			-			-			-			-
Divestments		-		-		-		-			-			-			-			-			-
Discoveries		-		-		-		-			-			-			-			-			-
Extensions and Improved Recovery		-		-		-		5,621			5,143			10,764			7,775			2,251			10,026
Economic Factors		-		-		-		-			-			-			-			-			-
Technical Revisions		-		-		-		7,065			(17,813	)		(10,748	)		1,120			(6,296	)		(5,176	)
Production		-		-		-		(2,810	)		-			(2,810	)		(4,052	)		-			(4,052	)
December 31, 2007		-		-		-		24,676			24,551			49,227			30,701			10,795			41,496

TOTAL ENERPLUS	Light & Medium 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, 2006		93,109			25,327			118,436			31,130			8,903		40,033			8,730			47,998		56,728
Acquisitions		2			-			2			-			-		-			-			-		-
Divestments		-			-			-			-			-		-			-			-		-
Discoveries		251			63			314			-			-		-			-			-		-
Extensions and Improved Recovery		8,633			2,046			10,679			1,870			1,301		3,171			-			4,064		4,064
Economic Factors		1,581			343			1,924			548			337		885			-			-		-
Technical Revisions		(1,054	)		(3,431	)		(4,485	)		797			383		1,180			(162	)		2,868		2,706
Production		(9,262	)		-			(9,262	)		(3,170	)		-		(3,170	)		-			-		-
December 31, 2007		93,260			24,348			117,608			31,175			10,924		42,099			8,568			54,930		63,498

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, 2006		12,481			3,708			16,189			892,580			336,920			1,229,500			294,214			142,089			436,303
Acquisitions		4			-			4			3,489			7,530			11,019			587			1,255			1,842
Divestments		-			-			-			(2,586	)		(252	)		(2,838	)		(431	)		(42	)		(473	)
Discoveries		1			(1	)		-			95			14			109			267			65			332
Extensions and Improved Recovery		558			179			737			35,218			14,731			49,949			16,931			10,045			26,976
Economic Factors		113			20			133			5,148			1,079			6,227			3,100			880			3,980
Technical Revisions		(209	)		(176	)		(385	)		(14,354	)		(34,071	)		(48,425	)		(3,020	)		(6,035	)		(9,055	)
Production		(1,467	)		-			(1,467	)		(90,786	)		-			(90,786	)		(29,030	)		-			(29,030	)
December 31, 2007		11,481			3,730			15,211			828,804			325,951			1,154,755			282,618			148,257			430,875

44

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(1)	Heavy		Light & Medium		Bitumen		NGLs		Natural Gas		Total
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Bcf)		(Mbbls)
Aggregate Prior to 2005		3,029		2,857		-		860		141.0		30,246
2005		768		2,524		9,308		414		55.0		22,181
2006		282		2,551		-		150		31.0		8,150
2007		858		4,782		-		215		24.1		9,865

Probable Undeveloped Reserves

	Crude Oil
Year(1)	Heavy		Light & Medium		Bitumen		NGLs		Natural Gas		Total
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Bcf)		(Mbbls)
Aggregate Prior to 2005		-		3,889		47,747		367		81.7		65,628
2005		126		902		-		104		22.0		4,799
2006		39		1,052		6,935		90		13.0		10,283
2007		1,007		1,214		4,064		101		17.7		9,342

Note:

(1) First attributed volumes include additions during the year and do not include revisions to previous undeveloped reserves.

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.

Significant Factors or Uncertainties

Enerplus has booked certain Probable Reserves related to the SAGD development of its Joslyn Project that are subject to decisions regarding an optimal development plan which may result in mining certain areas of the lease currently designated for SAGD. Furthermore, Enerplus’ reserves data do not reflect the Alberta government’s proposals for a new royalty regime planned to be effective January 1, 2009. Other than the foregoing, Enerplus does not anticipate any other significant economic factors or other significant uncertainties which may affect any particular components of its reserves data.

For further information, see “Risk Factors  - Enerplus’ actual reserves and resources will vary from its reserve and resource estimates, and those variations could be material” and “Risk Factors  - The proposed new Alberta royalty regime may adversely impact Enerplus and its operations and reserves”.

Proved and Probable Reserves Not on Production

Enerplus has approximately 7,683 MBOE of Proved plus Probable Reserves which are capable of production but which, as of December 31, 2007, 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.

45

SUPPLEMENTAL OPERATIONAL INFORMATION

Finding and Development and Finding, Development and Acquisition Costs

Finding and development (“F&D”) and finding, development and acquisition (“FD&A”) costs can be calculated either including or excluding changes during the year in estimated future development capital (“FDC”). F&D and FD&A costs calculated under NI 51-101 include changes during the year in estimated FDC as this provides a more representative view of the full cost of reserve additions as it accounts for future costs to bring the reserves to market. Under the historical method, F&D and FD&A costs are understated as reserves are included without taking into account the future capital expenditures required to fully develop the reserve base. We have included both the NI 51-101 method, which includes changes during the year in estimated FDC, and the historical method for comparison purposes. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year. For information on the use of the term “BOE” see “Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information”.

In 2007, Enerplus added 27.6 MMBOE of Proved plus Probable Reserves through its conventional capital development program and experienced negative technical revisions of 11.7 MMBOE of Proved plus Probable Reserves. As a result, on a net basis, Enerplus’ capital development program added 15.9 MMBOE, resulting in finding and development (“F&D”) costs of $19.97/BOE on its conventional oil and gas assets on a Proved plus Probable Reserves basis.

Enerplus’ total spending on its conventional asset base delivered a FD&A cost of $19.79/BOE on a Proved plus Probable Reserves basis, including FDC. Enerplus’ three-year average conventional Proved plus Probable FD&A cost was $19.57/BOE, including changes in FDC.

The F&D cost on Enerplus’ oil sands assets was $21.16/bbl based on Proved plus Probable Reserves, which reflects a significant increase in FDC associated with the SAGD development. Enerplus’ 2007 oil sands acquisition activity consisted solely of the acquisition of the Kirby Lease, which did not add any reserves or production but has a “best estimate” contingent resource estimate of 244 MMbbls (see “Operational Information  - Enerplus’ Play Types  - Oil Sands  - Kirby Project”). As Enerplus moves forward with the development of the Kirby Lease, it expects to move certain contingent resources into the Probable Reserves category. Enerplus’ Proved plus Probable oil sands FD&A costs in 2007 were $51.03/bbl.

Enerplus’ combined (conventional plus oil sands) 2007 corporate F&D cost was $20.33/BOE and its FD&A cost was $27.69/BOE (with both measures including changes in FDC). Enerplus’ combined three-year average F&D cost was $17.96/BOE and its combined three-year average FD&A cost was $20.69/BOE.

F&D and FD&A Costs (Including Net Change in Future Development Capital as per NI 51-101) ($ millions except for per BOE amounts)	2007		2006		2005
PROVED RESERVES
Conventional Oil and Natural Gas
Capital expenditures	$	348.3	$	452.1	$	335.5
Net change in Future Development Capital	$	39.3	$	22.3	$	97.4
Gross reserve additions (MMBOE)		17.9		16.1		28.8
F&D costs ($/BOE)	$	21.65	$	29.47	$	15.03
Three year averages F&D cost ($/BOE)(1)	$	20.62	$	15.54		n/a
Capital expenditures and net acquisitions	$	409.8	$	502.0	$	973.0
Net change in Future Developments Costs	$	48.5	$	8.0	$	184.7
Gross company reserve additions (MMBOE)		20.4		18.6		53.7
FD&A costs ($/BOE)	$	22.47	$	27.42	$	21.56
Three year average FD&A costs ($/BOE)(1)	$	22.93	$	19.80	$	24.02

46

F&D and FD&A Costs (Including Net Change in Future Development Capital as per NI 51-101) ($ millions except for per BOE amounts)	2007			2006			2005
Oil Sands
Capital expenditures	$	38.9		$	39.1		$	33.2
Net change in Future Development Capital	$	(1.7	)	$	(10.8	)	$	44.6
Gross reserve additions (MMBOE)		(0.2	)		(0.1	)		9.5
F&D costs ($/BOE)	$	(186.00	)	$	(283.00	)	$	8.19
Three year averages F&D cost ($/BOE)(1)	$	15.58		$	12.17			n/a
Capital expenditures and net acquisitions	$	242.0		$	19.4		$	33.2
Net change in Future Development Costs	$	(1.7	)	$	(13.6	)	$	44.6
Gross company reserve additions (MMBOE)		(0.2	)		(0.7	)		9.5
FD&A costs ($/BOE)	$	(1,201.50	)	$	(8.29	)	$	8.19
Three year average FD&A costs ($/BOE)(1)	$	37.66		$	10.44		$	9.51
Total Enerplus
Capital expenditures	$	387.2		$	491.2		$	368.7
Net change in Future Development Capital	$	37.6		$	11.5		$	142.0
Gross reserve additions (MMBOE)		17.7			16.0			38.3
F&D costs ($/BOE)	$	24.00		$	31.42		$	13.33
Three year averages F&D cost ($/BOE)(1)	$	19.98		$	15.16			n/a
Capital expenditures and net acquisitions	$	651.8		$	521.4		$	1,006.2
Net change in Future Development Costs	$	46.8		$	(5.6	)	$	229.3
Gross company reserve additions (MMBOE)		20.2			17.9			63.2
FD&A costs ($/BOE)	$	34.58		$	28.82		$	19.55
Three year average FD&A costs ($/BOE)(1)	$	24.18		$	19.20		$	22.73
PROVED PLUS PROBABLE RESERVES
Conventional Oil and Natural Gas
Capital expenditures	$	348.3		$	452.1		$	335.5
Net change in Future Development Capital	$	(30.7	)	$	50.7		$	92.1
Gross reserve additions (MMBOE)		15.9			18.3			32.0
F&D costs ($/BOE)	$	19.97		$	27.48		$	13.36
Three year averages F&D cost ($/BOE)(1)	$	18.85		$	20.22			n/a
Capital expenditures and net acquisitions	$	409.8		$	502.0		$	973.0
Net change in Future Development Costs	$	(12.0	)	$	54.4		$	197.7
Gross company reserve additions (MMBOE)		20.1			21.9			66.6
FD&A costs ($/BOE)	$	19.79		$	25.41		$	17.58
Three year average FD&A costs ($/BOE)(1)	$	19.57		$	18.10		$	15.97
Oil Sands
Capital expenditures	$	38.9		$	39.1		$	33.2
Net change in Future Development Capital	$	105.0		$	34.3		$	33.4
Gross reserve additions (MMBOE)		6.8			6.9			5.4
F&D costs ($/BOE)	$	21.16		$	10.64		$	12.33
Three year averages F&D cost ($/BOE)(1)	$	14.86		$	6.91			n/a
Capital expenditures and net acquisitions	$	242.0		$	19.4		$	33.2
Net change in Future Development Costs	$	105.0		$	15.6		$	33.4
Gross company reserve additions (MMBOE)		6.8			3.6			5.4
FD&A costs ($/BOE)(1)	$	51.03		$	9.72		$	12.33
Three year average FD&A costs ($/BOE)(1)	$	28.39		$	6.63		$	6.50
Total Enerplus
Capital expenditures	$	387.2		$	491.2		$	368.7
Net change in Future Development Capital	$	74.3		$	85.0		$	125.5
Gross reserve additions (MMBOE)		22.7			25.2			37.4
F&D costs ($/BOE)	$	20.33		$	22.87		$	13.21
Three year averages F&D cost ($/BOE)(1)	$	17.96		$	13.52			n/a
Capital expenditures and net acquisitions	$	651.8		$	521.4		$	1,006.2
Net change in Future Development Costs	$	93.0		$	70.0		$	231.1
Gross company reserve additions (MMBOE)		26.9			25.5			72.0
FD&A costs ($/BOE)(1)	$	27.69		$	23.19		$	17.18
Three year average FD&A costs ($/BOE)(1)	$	20.69		$	14.90		$	13.46

Note:

(1) Calculated over a three year period.

47

F&D and FD&A Costs (Excluding Changes in Future Development Capital) ($ millions except for per BOE amounts)	2007			2006			2005
PROVED RESERVES
Conventional Oil and Natural Gas
Capital expenditures	$	348.3		$	452.1		$	335.5
Gross reserve additions (MMBOE)		17.9			16.1			28.8
F&D Cost ($/BOE)	$	19.46		$	28.08		$	11.65
Three year averages F&D costs ($/BOE)(1)	$	18.09		$	13.17		$	9.87
Capital expenditures and net acquisitions	$	409.8		$	502.0		$	973.0
Gross company reserve additions (MMBOE)		20.4			18.6			53.7
FD&A costs ($/BOE)	$	20.09		$	26.99		$	18.12
Three year average FD&A costs ($/BOE)(1)	$	20.33		$	17.55		$	14.94
Oil Sands
Capital expenditures	$	38.9		$	39.1		$	33.2
Gross reserve additions (MMBOE)		(0.2	)		(0.1	)		9.5
F&D Cost ($/BOE)	$	(194.50	)	$	(391.00	)	$	3.49
Three year averages F&D costs ($/BOE)(1)	$	12.09		$	8.57		$	4.81
Capital expenditures and net acquisitions	$	242.0		$	19.4		$	33.2
Gross company reserve additions (MMBOE)		(0.2	)		(0.7	)		9.5
FD&A costs ($/BOE)	$	(1,210.00	)	$	(27.71	)	$	3.49
Three year average FD&A costs ($/BOE)(1)	$	34.26		$	6.92		$	4.81
Total Enerplus
Capital expenditures	$	387.2		$	491.2		$	368.7
Gross reserve additions (MMBOE)		17.7			16.0			38.3
F&D Cost ($/BOE)	$	21.88		$	30.70		$	9.63
Three year averages F&D costs ($/BOE)(1)	$	17.32		$	12.65		$	9.26
Capital expenditures and net acquisitions	$	651.8		$	521.4		$	1,006.2
Gross company reserve additions (MMBOE)		20.2			17.9			63.2
FD&A costs ($/BOE)	$	32.27		$	29.13		$	15.92
Three year average FD&A costs ($/BOE)(1)	$	21.51		$	16.88		$	14.30
PROVED PLUS PROBABLE RESERVES
Conventional Oil and Natural Gas
Capital expenditures	$	348.3		$	452.1		$	335.5
Gross reserve additions (MMBOE)		15.9			18.3			32.0
F&D Cost ($/BOE)	$	21.91		$	24.70		$	10.48
Three year averages F&D costs ($/BOE)(1)	$	17.16		$	16.66		$	12.48
Capital expenditures and net acquisitions	$	409.8		$	502.0		$	973.0
Gross company reserve additions (MMBOE)		20.1			21.9			66.6
FD&A costs ($/BOE)	$	20.39		$	22.92		$	14.61
Three year average FD&A costs ($/BOE)(1)	$	17.36		$	15.55		$	13.20
Oil Sands
Capital expenditures	$	38.9		$	39.1		$	33.2
Gross reserve additions (MMBOE)		6.8			6.9			5.4
F&D Cost ($/BOE)	$	5.72		$	5.67		$	6.15
Three year averages F&D costs ($/BOE)(1)	$	5.82		$	1.34		$	0.86
Capital expenditures and net acquisitions	$	242.0		$	19.4		$	33.2
Gross company reserve additions (MMBOE)		6.8			3.6			5.4
FD&A costs ($/BOE)	$	35.59		$	5.39		$	6.15
Three year average FD&A costs ($/BOE)(1)	$	18.65		$	1.07		$	0.86
Total Enerplus
Capital expenditures	$	387.2		$	491.2		$	368.7
Gross reserve additions (MMBOE)		22.7			25.2			37.4
F&D Cost ($/BOE)	$	17.06		$	19.49		$	9.86
Three year averages F&D costs ($/BOE)(1)	$	14.62		$	8.95		$	6.78
Capital expenditures and net acquisitions	$	651.8		$	521.4		$	1,006.2
Gross company reserve additions (MMBOE)		26.9			25.5			72.0
FD&A costs ($/BOE)	$	24.23		$	20.45		$	13.98
Three year average FD&A costs ($/BOE)(1)	$	17.52		$	11.51		$	10.09

Note:

(1) Calculated over a three year period.

48

Acquisitions and Divestments

In 2007 Enerplus acquired approximately 4.3 MMBOE of company interest Proved plus Probable conventional oil and natural gas reserves, the majority of which was through the acquisition of gross overriding royalty interests in the Jonah field in Wyoming for consideration of $61 million, as described under “General Development of Enerplus Resources Fund  - Developments in the Past Three Years  - Acquisition of Gross Overriding Royalty Interests in U.S.”. Enerplus also acquired a 100% working interest in the Kirby Lease for $203.1 million, as described under “General Development of Enerplus Resources Fund  - Developments in the Past Three Years  - Acquisition of Kirby” and “Operational Information  - Enerplus’ Play Types  - Kirby Project”. The following table outlines Enerplus’ acquisition and divestment activity in 2007.

2007 Acquisition and Divestment Summary

Conventional Oil and Natural Gas	Cost/ Proceeds(1)		Estimated Proved plus Probable Reserves		Production(2)		Cost of Proved plus Probable Reserves		Cost per Daily Barrel of Production
	(in $ millions)		(MBOE)		(BOE/d)		($/BOE)		(in $ thousands)
Acquisitions	$	71.1		4,773		667	$	14.90	$	106.6
Divestments		9.6		523		128		18.36		75.0
Net Conventional Oil and Natural Gas Acquisitions	$	61.5		4,250		539	$	14.47	$	114.1
Oil Sands Acquisitions(3)	$	203.1		-		-		n/a		n/a

Notes:

(1) After adjustment for working capital and excluding future development.

(2) Represents the approximate production at the time of acquisition or divestment.

(3) In the GLJ Oil Sands Resources Report, GLJ attributed a best estimate of 244 MMBOE of contingent bitumen resources to the Kirby Lease. For information on the contingent resource estimates for the Kirby Lease and the risks and uncertainties associated therewith, see “Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information” and “Operational Information  - Enerplus’ Play Types  - Oil Sands  - Kirby Project”.

Equity Investments

During 2007, Enerplus continued the strategy of investing equity in junior energy businesses with the potential for strategic benefits to Enerplus. To date, Enerplus has made investments in companies involved in conventional exploration and production in Canada and abroad, oil sands development and oil sands infrastructure. The relationships associated with these investments have provided insight into potentially attractive plays and technologies, increased deal flow, competitive advantages on acquisitions and enhanced monetization of non-core assets.

Enerplus plans to continue the strategy in 2008 given the strategic and financial success of the program to date. Since the implementation of this strategy, Enerplus has invested approximately $70 million in over ten investments, has realized sales proceeds of over $41 million and has a current portfolio that Enerplus estimates was valued at approximately $175 million at December 31, 2007.

Health, Safety and Environment

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.

49

Health and Safety

Enerplus’ safety performance record in 2007 saw significant improvement with no employee lost-time injury incidents and only one employee medical aid injury recorded. This resulted in a recordable injury frequency rate of 0.17 injuries per 200,000 man hours compared to 1.43 injuries per 200,000 man hours in 2006. In addition, Enerplus’ contractor lost-time injury frequency substantially improved from 0.97 injuries per 200,000 man hours in 2006 to a rate of 0.10 injuries in 2007. This improvement equates to having only one contractor lost-time injury incident in all of 2007.

Health, safety and environmental (“HSE”) risks influence the workforce, operating costs and the establishment of regulatory standards. Enerplus has established an HSE Management System designed to:

• provide staff with the training and resources needed to complete work safely and effectively;

• incorporate hazard assessment and risk management as an integral part of everyday business;

• monitor performance to ensure that its operations comply with legal obligations and the internally-imposed standards; and

• identify and manage environmental liabilities associated with its existing asset base and potential acquisitions.

In addition, in 2007 Enerplus also undertook the following initiatives:

• implementation of a new field hazard awareness, identification and reporting program which Enerplus believes successfully contributed to its significant improvement in safety performance;

• implementation of two new head office-based HSE positions (i.e., one HSE Regulatory Compliance Coordinator and one HS Team Lead position) and four new field-based HS field support positions (i.e., Field Health and Safety Advisors) to provide an enhanced pro-active support service to Operations and aid in continued performance improvement; and

• updated and revised its Corporate Emergency Response Plan (“ERP”) and facilitated an extensive arrangement of ERP awareness and response training.

Environment

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 participates in the CAPP (Canadian Association of Petroleum Producers) Stewardship Program at the highest level, platinum. Enerplus’ participation requires its commitment to continuous improvement in its HSE management system including sound planning and implementation, open communication and demonstrated performance and a thorough external audit of its activities at least once every five years;

• Site restoration (remediation, reclamation and abandonment) expenditures increased 31% year-over-year to $20.5 million in 2007. Reclamation and site abandonment expenditures for 2007 totaled $8.2 million, up $2.1 million from 2006 expenditures, due mainly to an increase in the number of wells abandoned during the year. Remediation expenditures for 2007 totaled $12.3 million, up from $9.6 million in 2006. Site restoration occurs when areas are returned to their original state once operations have been completed;

• Enerplus enhanced its pipeline gathering system 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’ pipeline gathering system through ongoing risk assessment. In 2007, 93% of Enerplus’ 6,500 kilometers of operated gathering pipelines were assessed; and

• Enerplus has a site inspections program and a corrosion risk management program designed to ensure compliance with HSE laws and regulations. Enerplus carries insurance to cover a portion of its property losses, liability and business interruption. HSE updates and risks are reviewed regularly by the HSE committee comprised of members of the board of directors of EnerMark.

50

Enerplus carries out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice. At present, Enerplus believes that it meets all applicable environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet its ongoing environmental obligations. The costs incurred by Enerplus in respect of continued environmental compliance and site restoration costs amounted to approximately 4% of the total development expenditures incurred by Enerplus in 2007. See “Industry Conditions  - Environmental Regulation” and “Risk Factors”.

Overall, Enerplus believes its Health, Safety and Environment 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.

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, 2007, Enerplus employed a total of 640 persons.

51

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 and on EDGAR at www.sec.gov on December 10, 2007.

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 an unlimited number of Special Voting Rights. Each Trust Unit represents an equal undivided beneficial interest in the Fund and 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.

For description of the Special Voting Right issued on February 13, 2008 in connection with the Focus Exchangeable LP Units assumed by Enerplus in connection with its acquisition of Focus, see Appendix “G”  - Information Regarding Focus Energy Trust.

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.

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The Trustee shall be removed by notice in writing delivered by EnerMark to the Trustee if the Trustee fails to meet certain criteria stated within the Trust Indenture or with the approval of at least 662/3% of the votes cast at a meeting of unitholders called for that purpose. The Trustee or any successor may resign upon 60 days notice to EnerMark. Such resignation or removal shall become effective upon the acceptance of appointment by a successor trustee. If the Trustee is removed by EnerMark, EnerMark may appoint a successor trustee. If the Trustee resigns or is removed by unitholders, its successor must be either appointed by EnerMark or the unitholders. If a successor trustee does not accept its appointment as trustee, a court may appoint the successor trustee.

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

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

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

At the annual general and special meeting of the Fund’s unitholders to be held on May 9, 2008, the Fund’s unitholders will be asked to approve an extraordinary resolution to remove CIBC Mellon Trust Company as Trustee and appoint Computershare Trust Company of Canada to replace CIBC Mellon Trust Company as Trustee of the Fund.

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.

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

Certain Restrictions on Powers of the Trustee and EnerMark

The Trust Indenture provides that neither the Trustee nor EnerMark may, without approval of the Fund’s unitholders by ordinary resolution (meaning approval by a majority of the votes cast), vote shares of EnerMark to appoint, remove or replace the directors of EnerMark or appoint or change the auditors of the Fund, except to fill a vacancy in the office of auditors. Additionally, the Trust Indenture provides that neither the Trustee nor EnerMark may, without approval of the unitholders by extraordinary resolution (meaning approval by at least 662/3% of the votes):

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

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

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

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

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

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

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Non-Resident Ownership Provisions

As long as the Fund is able to meet the “TCP Exception” described under “Risk Factors  - Risks Related to Enerplus’ Structure and Ownership of the Trust Units  - Changes in tax and other laws may adversely affect unitholders”, there is no specified limitation in the Tax Act as to the level of non-Canadian resident ownership of the Trust Units. However, absent the TCP Exception, in order for the Fund to maintain its status as a mutual fund trust under the Tax Act, it may be necessary for the Fund to ensure that it has not been established or maintained primarily for the benefit of non-residents of Canada (“non-residents”) within the meaning of the Tax Act or to otherwise restrict the number of Trust Units held by non-residents. Accordingly, the Trust Indenture provides that, from time to time, EnerMark may restrict the number of Trust Units owned by non-residents and take all necessary steps to monitor the ownership of the Trust Units such that the Fund maintains the status of a unit trust and mutual fund trust for the purposes of the Tax Act. The Trust Indenture also provides that, if at any time EnerMark becomes aware that the number of Trust Units owned by non-residents exceeds 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 royalty, interest, 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.

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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 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.

For a description of the monthly payments to be made on the Focus Exchangeable LP Units, see Appendix “G”  - Information Regarding Focus Energy Trust in this Annual Information Form.

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.

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Redemption Right

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

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

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

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

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

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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 registered unitholders and unitholders who elect to receive such information under applicable securities laws within appropriate regulatory time periods in each calendar year. The fiscal year-end of the Fund is December 31.

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

Auditors

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

Amendments to the Trust Indenture

The Trust Indenture may be amended from time to time by the Trustee, EnerMark and ERC. Material amendments to the Trust Indenture require approval by at least 662/3% of the votes cast at a meeting of the unitholders called for that purpose. However, the Trustee, EnerMark and ERC may, without the approval of the unitholders, make amendments to the Trust Indenture for the purposes of:

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

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

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

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

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

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

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(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 Other Payments Made to the Fund

The Fund’s primary direct 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, the Fund indirectly receives payments of interest and principal on unsecured, subordinated debt issued among certain of the Fund’s subsidiaries, including by EnerMark. Outlined below is a description of the royalties granted by EnerMark, ERC and Enerplus Oil & Gas to the Fund and the inter-company subordinated debt issued by certain subsidiaries 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. 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.

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Unsecured, Subordinated Promissory Notes

Certain of the Fund’s direct and indirect subsidiaries have issued unsecured, subordinated promissory notes and indebtedness to other of the Fund’s subsidiaries to facilitate the payment of cash from the Operating Subsidiaries to the Fund for subsequent distribution to unitholders. For instance, 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 are loaned 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. Other inter-company indebtedness within the Fund’s corporate structure has similar terms.

Payments on Securities Held by the Fund

The Fund receives distribution and dividend payments on certain securities it holds directly, including cash distributions on the limited partnership units of each of Enerplus Finance Limited Partnership and Enerplus Limited Partnership II, which directly or indirectly receive cash payments from the Operating Subsidiaries.

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 terms of EnerMark’s Credit Facilities and Senior Unsecured 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 the Fund’s subsidiaries to the Fund, and the related cash distributions from the Fund to unitholders, may be adversely affected if EnerMark or other subsidiaries of the Fund are in default of such third party indebtedness or if there are variations in the terms of the 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 “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 “Statement of Corporate Governance Practices” in the Fund’s information circular and proxy statement dated March 13, 2008. 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 must be, and is proposed to be, renewed and approved by the Fund’s unitholders at the 2008 annual general and special meeting scheduled for May 9, 2008. 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 existing 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 “Corporate Governance”. A copy of the draft Amended and Restated Unitholder Rights Plan Agreement proposed to be approved by the Fund’s unitholders on May 9, 2008 is also available on the Fund’s website at www.enerplus.com.

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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, 2007, EnerMark had senior debt facilities comprised of a $1.0 billion bank credit facility, which was increased to $1.4 billion concurrent with the completion of Enerplus’ acquisition of Focus on February 13, 2008 (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.

Set forth below is a description of the material terms of the Bank Credit Facility and the Senior Unsecured Notes. A copy of the Bank Credit Facility (including all amendments thereto) and a form of each series of Senior Unsecured Notes (including all amendments thereto) has been filed on March 18, 2008 as a “Material document” on the Fund’s SEDAR profile at www.sedar.com and on Form 6-K on EDGAR at www.sec.gov.

Bank Credit Facility

The $1.4 billion Bank Credit Facility is an unsecured, covenant-based credit agreement with a syndicate of financial institutions that currently is scheduled to mature in November 2010, subject to further extension by the lenders. As at December 31, 2007, $497 million was outstanding under this facility, and following completion of the acquisition of Focus on February 13, 2008, an additional $340 million was drawn under this facility to settle Focus’ outstanding indebtedness. 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.

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Consolidated Total Debt:	The aggregate of Consolidated Senior Debt and Subordinated Debt.
Material Acquisition:	An acquisition or series of acquisitions which increases the tangible assets of Enerplus by more than 5%.
Subordinated Debt:	Debt which, by its terms, is subordinated to the Bank Credit Facility (but excludes convertible debentures which allow the Fund to issue Trust Units or other securities of the Fund in satisfaction of interest or principal).
Total Capitalization:	The aggregate of Consolidated Senior Debt and the Fund’s unitholders’ equity (calculated in accordance with GAAP as shown on the Fund’s consolidated balance sheet).

Senior Unsecured Notes

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

Terms of Notes	US$175 million	US$54 million
Issued:	June 19, 2002	October 1, 2003
Maturity:	June 19, 2014	October 1, 2015
Coupon rate:	6.62%	5.46%
Semi-annual interest paid yearly on:	June 19 and December 19	April 1 and October 1
Principal payments in five annual equal 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 million 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%. In September 2007 Enerplus entered into foreign exchange swaps that effectively fix the five principal payments on the US$54 million notes at a CAD/US exchange rate of $1.02.

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, 2007 and under the heading “Liquidity and Capital Resources  - Long-Term Debt” in Enerplus’ management’s discussion and analysis for the year ended December 31, 2007. 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 other subsidiaries, and therefore ahead of distributions from the Fund to its unitholders. See “Information Respecting Enerplus Resources Fund  - Description of the Royalty Agreements and Other Payments Made to the Fund” 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 the Fund 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.

In connection with its acquisition of Focus effective February 13, 2008, Enerplus assumed a total of 9,086,666 Focus Exchangeable LP Units (as of February 13, 2008), each of which is exchangeable, for no additional consideration, into 0.425 of a Trust Unit. Additionally, each Focus Exchangeable LP Unit is entitled to receive 0.425 of the amount of distributions paid by the Fund in respect of a Trust Unit. See Appendix “G”  - Information Regarding Focus Energy Trust.

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, including royalty burdens, 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 and other securities that may be entitled to receive cash distributions, such as the Focus Exchangeable LP 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, 2007, approximately 26% of the cash flow from operating activities was retained.

The after-tax return from an investment in the Fund’s Trust Units to unitholders subject to Canadian income tax can be made up of both a return on and a return of capital. That composition may change over time, thus affecting an investor’s after-tax return. For Canadian resident unitholders, 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). For unitholders who are not residents of Canada, a 15% withholding tax is levied on returns of capital by the Fund.

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 2004:

Month of Record and Payment Date	2008		2007		2006		2005		2004
January(1)	$	0.42	$	0.42	$	0.42	$	0.35	$	0.35
February		0.42		0.42		0.42		0.35		0.35
March		0.42		0.42		0.42		0.35		0.35
April		N/A		0.42		0.42		0.35		0.35
May		N/A		0.42		0.42		0.35		0.35
June		N/A		0.42		0.42		0.35		0.35
July		N/A		0.42		0.42		0.35		0.35
August		N/A		0.42		0.42		0.37		0.35
September		N/A		0.42		0.42		0.37		0.35
October		N/A		0.42		0.42		0.37		0.35
November		N/A		0.42		0.42		0.42		0.35
December		N/A		0.42		0.42		0.42		0.35

Note:

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

Monthly cash distributions paid to U.S. resident unitholders are converted to U.S. dollars based upon the actual Canadian to U.S. dollar exchange rate on the distribution payment date.

The historical distribution payments described above may not be reflective of future distribution payments, and future distribution payouts are not assumed. Future distributions 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” in this Annual Information Form, and in particular see the risk factors entitled: “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”; “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”; “Enerplus’ distributions may be reduced during periods in which it makes capital expenditures or debt repayments using cash flow”; “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’ third party indebtedness may limit the timing or amount of the distributions that the Fund pays to unitholders” and “Changes in tax and other laws may adversely affect unitholders”.

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 2% of the Fund’s 2007 distributions was a return of capital and approximately 98% was taxable to unitholders as other 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.

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Based upon the computation of current and accumulated earnings and profit in accordance with U.S. federal income tax principles, approximately 93% of the distributions paid by the Fund during 2007 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’ 2007 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. On March 24, 2007, Bill 1672 was introduced into the U.S. House of Representatives which, if enacted as presented, would make dividends from Canadian income funds such as the Fund ineligible for treatment as a “Qualified Dividend”, and a comparable Bill was introduced in the U.S. Senate. The dividend would then become “non-qualified dividends from a foreign corporation” subject to the normal rates of tax commencing with dividends received after the date of enactment. The proposed bill still requires the approval of the House of Representatives, the Senate and the President prior to it being enacted. Therefore, it is uncertain as to if or when the bill will be enacted, or if it will be enacted as presented. 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 income portion of the distribution as computed under Canadian tax law, and the portion of the distribution which was a return of capital. 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 73% of Enerplus’ 2007 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 Resources Conservation Board (the “ERCB”) (which generally regulates the oil and gas industry pursuant to various statutes, including the Oil Sands Conservation Act (Alberta)), the Alberta Utilities Commission (the “AUC”) (with respect to certain natural gas transmission matters) 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 ERCB 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 ERCB, 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. Crude oil exported from Canada is subject to regulation by the National Energy Board (the “NEB”) and the Government of Canada. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been obtained from the National Energy Board (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

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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, seasonal factors, 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.

Province of Alberta

The Province of Alberta imposes royalties of varying rates on the production of crude oil from lands in which it owns the mineral rights. On October 25, 2007, the Government of Alberta unveiled a new royalty regime. The new regime would introduce new royalties for conventional oil, natural gas and bitumen effective January 1, 2009 that have rate components that are linked to price and production levels and will apply to both new and existing oil sands projects and conventional oil and gas activities.

At present, 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 new royalty formula for conventional oil will operate on a sliding rate formula containing separate elements that account for the world oil price and well production. Royalty rates for conventional oil will range up to 50 percent, with rate component caps once the WTI price of conventional oil reaches $116 per barrel (in Canadian dollars) or at a well productivity of 151 bbls/d. Royalties for natural gas liquids will be set at 40 percent for pentanes and 30 percent for butanes and propane.

The royalty payable to the Alberta government in respect of natural gas is currently 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. Under the new royalty regime, natural gas royalties will be set by a sliding rate formula sensitive to a combination of price and production volume, and to a lesser extent well depth. New natural gas royalty rates will range from five percent to 50 percent with rate caps at a natural gas price of $18.72/Mcf or at a well productivity of 568 Mcf/d.

Alberta’s current royalty system for oil sands, introduced in 1997, was designed to support the development of the oil sands industry. Currently, in respect of oil sands projects having regulatory approval, a royalty of one percent of gross bitumen revenue is payable prior to the payout of specified allowed costs, including certain exploration and development costs, operating costs and a return allowance. Once such allowed costs have been recovered, a royalty of the greater of: (a) one percent of gross bitumen revenue; and (b) 25 percent of net bitumen revenue (calculated as being gross bitumen revenue less operating costs and additional capital expenditures incurred since payout (“net royalty”)) is levied. Enerplus’ oil sands projects are currently at pre-payout status.

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Under the new regime, the Government of Alberta will increase its royalty share from oil sands development by introducing price-sensitive formulas which will be applied both before and after specified allowed costs have been recovered. The base royalty will start at one percent and will rise with the world oil price, as reflected by the WTI crude oil price, when it is above $55 per barrel (in Canadian dollars), to a maximum of nine percent when the WTI crude oil price is $120 per barrel (in Canadian dollars) or higher. After payout, the net royalty on oil sands will start at 25 percent and will increase for every dollar the WTI crude oil price is above $55 per barrel to 40 percent when the WTI crude oil price is $120 per barrel or higher. The Government of Alberta has announced that it intends to review, and if necessary, revise current rules and enforcement procedures with a view to clearly defining what expenditures will qualify as specified allowed costs.

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof. See “Risk Factors  - Risks Relating to Enerplus Business and Operations  - The proposed new Alberta royalty regime may adversely impact Enerplus and its operations and reserves”.

Province of Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered “heavy oil”, “southwest designated oil” or “non heavy oil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourth tier oil” introduced October 1, 2002, “third tier oil”, “new oil” or “old oil”) of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all “fourth tier oil” to 20% for “old oil”. Marginal royalty rates are 30% for all “fourth tier oil” to 45% for “old oil”.

The amount payable as a royalty 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 quantity produced in a given month, the type of natural gas and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are “fourth tier gas” introduced October 1, 2002, “third tier gas”, “new gas” and “old gas”. The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for “fourth tier gas” and 20% for “old gas”. The marginal royalty rates are between 30% for “fourth tier gas” and 45% for “old gas”.

On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan:

• A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic meters in a month.

• A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002 was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero per cent.

• The elimination of the re entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002 will receive the “fourth tier” royalty/ tax rates and new incentive volumes.

In 1975 the Government of Saskatchewan introduced a Royalty Tax Rebate (“RTR”) as a response to the federal government disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes. As of January 1, 2007 the remaining balance of any unused RTR will be limited in its carry forward to the years since the federal government had the initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.

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Province of British Columbia

Producers of oil and natural gas in the Province of British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil), or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for the Province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands (“Strategy”). The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities. In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia’s heartlands.

Some of the financial incentives in the Strategy include:

• Royalty credits of up to $30 million annually towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry.

• Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season.

On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province’s strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world’s leader in sustainable environmental management. With regards to the oil and gas industry, the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and gas sector. Among the changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishing of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) new the Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves.

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.

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

Environmental Regulation

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

In Alberta, environmental compliance is governed by the Environmental Protection and Enhancement Act (Alberta) (the “EPEA”) and the Oil and Gas Conservation Act (Alberta), both of which impose certain environmental responsibilities on oil and natural gas operators and working interest holders in Alberta and impose penalties for violations. The EPEA also imposes certain environmental responsibilities on the operators of oil sands in-situ extraction projects, pipelines, upgraders and cogeneration plants. In certain instances EPEA imposes significant penalties for violations. In Saskatchewan, environmental compliance is governed by the Environmental Management and Protection Act (Saskatchewan) and the Oil and Gas Conservation Act (Saskatchewan). In British Columbia, energy projects may be subject to review pursuant to the provisions of the Environmental Assessment Act (British Columbia), which rolls the previous processes for the review of major energy projects into a single environmental assessment process that contemplates public participation in the environmental review. Additionally, in its 2008 provincial budget, the Government of British Columbia proposed a carbon tax and a “cap and trade” system for large emitters of greenhouse gases.

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. The Canadian federal government has released emission reduction targets for large emitters (e.g., 100,000 tonnes of carbon dioxide per year at a single facility), which could result in increased capital expenditures and operating costs. Currently, Enerplus does not operate any facility classed within this large emitter category. However, once on-stream the Kirby Project would be within this range. Also, in late 2007 the Canadian federal government put forth an obligation for all industries to submit 2006 emissions information (by May 31, 2008) on all facilities emitting greater than 1,000 tonnes of carbon dioxide per year. It is believed this information will be used toward the forthcoming implementation plan. On March 10, 2007, the Canadian federal government proposed new regulations as part of its “Turning the Corner” plan that would require oil sands projects starting operations in 2012 and beyond to reduce greenhouse gas emissions, largely through carbon capture technology. The potential impact on oil sands producers is currently unclear given the draft nature of the regulations and the fact that carbon capture technology has not yet been proven on a large scale. Certain Canadian provincial governments (e.g., British Columbia, Alberta and Saskatchewan) have also released emission reduction targets. However, until implementation plans are 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”.

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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, 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 implementation of the SIFT Tax may 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 losses could occur under various circumstances, including if the other party to Enerplus’ hedge does not perform its obligations under the hedge agreement.

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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 the Credit Facilities, 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 Enerplus believes that its existing Credit Facilities are sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Enerplus or that additional funds can be obtained as required. 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 variables. 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, royalty rates and environmental laws) and other factors beyond the control of the Fund. In addition, the market value of the Fund’s Trust Units may decline if the Fund’s cash distributions decline in the future, and that decline may be material.

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Enerplus may require additional financing to maintain and expand its assets and operations.

In the normal course of making capital investments to maintain and expand Enerplus’ oil, NGLs, natural gas and bitumen reserves and resources, additional Trust Units may be issued which may result in a decline in production per Trust Unit and reserves and/or resources per Trust Unit. Additionally, from time to time, Enerplus may issue Trust Units or other securities from treasury in order to reduce debt and maintain a more optimal capital structure. Enerplus may also dispose of existing properties or assets as a means of financing alternative projects or developments. Conversely, to the extent that external sources of capital, including the availability of debt financing from banks or other creditors or the issuance of additional Trust Units or other securities, becomes limited or unavailable, Enerplus’ ability to make the necessary capital investments to maintain or expand its oil, NGLs, natural gas and bitumen reserves and resources will be impaired. To the extent that Enerplus is required to use additional cash flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the level of cash flow for distribution to the Fund’s unitholders will be reduced.

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 while offering limited relief to Enerplus' cost structure as a majority of its costs are incurred in Canadian dollars. Enerplus conducts certain of its business and operations in the United States and is therefore exposed to foreign currency risk on both revenues and costs 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 and the foreign exchange swaps that effectively fix the principal payments on its US$54 million of Senior Unsecured Notes issued in October 2003, each, as described in Note 7(b) to the Fund’s audited consolidated financial statements for the year ended December 31, 2007.

If Enerplus is unable to add or develop additional reserves or 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, develop or expand its oil and natural gas reserves and 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.

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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. The actual reserves and resources contained in Enerplus’ properties (including the Focus Properties) will vary from the estimates summarized in the Annual Information Form and those variations could be material. 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;

• 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 associated contingencies, and the 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 Enerplus’ oil sands projects in any particular period. No assurance can be provided as to the gravity or quality of bitumen produced from Enerplus’ oil sands projects. Additionally, as development plans for the Kirby Project or the Joslyn Project are developed or modified (and in particular with respect to the Joslyn Project’s SAGD development in respect of which Enerplus has booked certain Probable Reserves) and if a decision is made to mine certain portions currently designated as SAGD-designated parts of the Joslyn Project, the volume and estimated value of the Probable Reserves assigned to 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 SAGD development plans versus possible expansion of mine development plans.

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In addition, references to “contingent resources” or “resources” in this Annual Information Form do not constitute, and should be distinguished from, references to “reserves”. For additional information, see “Presentation of Enerplus’ Oil and Natural Gas Reserves, Resources and Production Information” and “Operational Information  - Enerplus’ Play Types  - Oil Sands”.

Enerplus may not realize the anticipated benefits of its acquisitions or disposition, including its recent acquisition of Focus.

From time to time, Enerplus may acquire additional oil and natural gas properties and related assets, such as its acquisition of Focus completed on February 13, 2008, which Enerplus acquired to strengthen its position in the oil and gas industry and to create the opportunity to create certain cost savings. Achieving the anticipated benefits of such acquisitions will depend in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as Enerplus’ ability to realize the anticipated growth opportunities and synergies from combining and integrating the acquired assets and properties into Enerplus’ existing business. These activities will require the dedication of substantial management effort, time and capital and other resources which may divert management’s focus and capital and other resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect Enerplus’ ability to achieve the anticipated benefits of future acquisitions.

Furthermore, potential investors should be aware that certain acquisitions, and in particular acquisitions in oil sands assets such as the acquisition of Kirby in the second quarter of 2007, and the development of those assets has required and will require significant capital expenditures from Enerplus, and Enerplus may not receive cash flow from operations from these acquisitions for several years. Accordingly, the timing and amount of capital expenditures may affect the amount of cash payments received by Enerplus from its Operating Subsidiaries and may adversely affect the amount of cash distributions paid to the Fund’s unitholders.

Enerplus may also from time to time dispose of properties and assets. These dispositions may consist of non-core properties or assets or may consist of assets or properties that are being monetized in order to fund alternative projects or development by Enerplus. There can be no assurance that Enerplus will realize the amount of desired proceeds from such dispositions or that such dispositions will be viewed positively by the financial markets, and such dispositions may negatively affect the trading price of the Trust Units.

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 a portion 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. Following completion of the Focus acquisition on February 13, 2008, approximately 30% 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.

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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 Joslyn 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 Joslyn Project, the construction or operations of the Joslyn Project or other facets of the Joslyn Project, any of which may adversely affect Enerplus.

Enerplus’ third party 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’ third party indebtedness, including the Credit Facilities, ranks ahead of payments of cash from the Operating Subsidiaries to the Fund and therefore reduces amounts available for distribution from the Fund to unitholders. Enerplus has an unsecured Bank Credit Facility available to it at variable interest rates. In addition, Enerplus has swapped both its US$175 million and US$54 million Senior Unsecured Notes with fixed interest rates into Canadian dollar denominated 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 the Bank 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 Bank Credit Facility and the holders of the Senior Unsecured Notes. See “Debt of Enerplus”.

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

The amounts available under Enerplus’ Credit Facilities 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’ Bank 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 Unsecured Notes commencing June 19, 2010 and on US$55.1 million of Senior Unsecured Notes commencing October 1, 2011. See “Debt of Enerplus”. Any failure to obtain replacement financing, or financing on favourable terms, may have a material adverse effect on Enerplus’ business, and distributions to unitholders may be materially reduced or eliminated, as repayment of such debt has priority over the payment of cash from the Operating Subsidiaries to the Fund, and as a result, from the Fund to unitholders.

The proposed new Alberta royalty regime may adversely impact Enerplus and its operations and reserves.

On February 16, 2007, the Alberta government began a review of its royalty regime for oil sands, conventional oil and natural gas and coalbed methane with the stated intention of assessing whether the existing royalty regime was providing Albertans with a fair return on Alberta’s natural resources while maintaining an internationally competitive system that allows the Alberta economy to continue to prosper. On October 25, 2007, the Alberta government released a report titled “The New Royalty Framework” (the “Report”) containing the government’s proposals for Alberta’s new royalty regime (the “Proposed Royalty Regime”), which is scheduled to take effect on January 1, 2009. The Proposed Royalty Regime includes the following features:

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• New, simplified royalty formulas for conventional oil and natural gas that will operate on sliding scales that are determined by commodity prices, well productivity and measured depths of natural gas wells. The formulas eliminate the need for conventional oil and natural gas tiers and several royalty exemption programs;

• A sliding scale will be implemented for oil sands royalty rates ranging from one to nine percent pre-payout and 25 to 40 percent post-payout depending on the price of oil;

• The province will exercise its existing right to receive “royalty-in-kind” on oil sands projects (i.e. raw bitumen delivered to the Crown-operated Alberta Petroleum Marketing Commission in lieu of cash royalties);

• The government will ensure that eligible expenditures and definitions of oil sands projects (also known as “ring fence” definition) that determine when a project has reached payout are tightly and clearly defined. Environmental “costs of doing business” will continue to be recognized as eligible expenditures;

• No grandfathering will be implemented for existing oil sands projects; and

• Substantial legislative, regulatory and systems updates will be introduced before changes become fully effective in January 2009.

Given that the Proposed Royalty Regime has not yet been finalized or passed into law, it is not possible at this time to determine the full impact of the Proposed Royalty Regime on Enerplus’ financial condition and operations, and in particular the extent to which the Proposed Royalty Regime will reduce Enerplus’ cash flow, which will in turn reduce the cash otherwise available for distribution by the Fund to its unitholders. Enerplus’ and Focus’ reserves and the future net revenue associated therewith as contained in the reserve reports summarized in this Annual Information Form do not reflect the revised royalty rates contemplated by the Proposed Royalty Regime and, after taking the Proposed Royalty Regime into account, such values may be adversely affected.

Enerplus cannot provide any assurance that the Proposed Royalty Regime will be implemented in the form proposed in the Report. If changes are made to the Proposed Royalty Regime before it is implemented by the Alberta government, such changes could be more adverse to Enerplus than the royalty regime proposed in the Report.

Enerplus’ operations are subject to certain risks inherent in the oil and natural gas business.

Enerplus’ business and operations are subject to certain risks inherent in the oil and natural gas business. Pipeline and transportation constraints experienced by oil producers in Montana, North Dakota and southeast Saskatchewan have become more pronounced as a result of strong crude oil prices and the increased drilling and development activities in these areas. If these restraints remain unresolved, Enerplus’ ability to transport its crude oil production in these regions may be impaired and could adversely impact Enerplus’ production volumes from these areas. Reduced production and/or transportation of such production may adversely affect Enerplus’ cash flow from operations and the distributions to the Fund’s unitholders.

Additionally, operational hazards, such as the previously announced fire that Enerplus experienced at its Giltedge property, may reduce Enerplus’ production volumes. Although Enerplus carries business interruption and property insurance in respect of such matters, and expects such insurance to negate a portion of the financial loss related to the fire at Giltedge relative to cash flows and reconstruction costs, there can be no assurance that insurance will be adequate to cover all losses resulting from such events or that the lost production will be restored in a timely manner.

The properties and assets that Enerplus may acquire in the future are subject to operational risks.

The risk factors set forth in this Annual Information Form relating to the oil and natural gas business and the operations, reserves and resources of Enerplus apply equally in respect of any future properties or assets that Enerplus may acquire. Enerplus generally conducts certain due diligence in connection with acquisitions but there can be no assurance that Enerplus will identify all of the potential risks and liabilities related to the subject properties.

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The Kirby properties acquired by Enerplus in the second quarter of 2007 currently contain certain producing and shut-in natural gas wells that may penetrate or otherwise result in the applicable petroleum and natural gas zones coming into communication with the bitumen resources on the Kirby Lease. There is a risk that if the production of natural gas from these zones penetrates or otherwise comes into communication with the bitumen resources in the Kirby Lease, there may be a loss of steam or steam chamber pressure in the SAGD bitumen extraction process and adversely affect SAGD recovery of bitumen. Enerplus did not acquire these wells, or the conventional petroleum and natural gas zones from which they produce or which are producible by these wells, or the accompanying abandonment, reclamation and environmental obligations associated with these wells, pursuant to the Kirby acquisition. The Kirby acquisition agreement provides that the vendors retain the rights to such wells and zones, and if it is determined that there is communication between the natural gas production zones and the bitumen resources, the parties intend to enter into an agreement whereby the vendors would agree to take such commercially reasonable actions or authorize Kirby to take such actions as may be necessary to mitigate such risk and, if appropriate, shut-in any potentially penetrating or communicating well. However, no assurance can be provided that the production or potential of natural gas over bitumen on the Kirby Lease will not pose a risk to the SAGD recovery of the bitumen resources on the lease.

Each of the Kirby Project and the Joslyn Project is in the early development stage and is subject to numerous risks.

Each of the Joslyn Project and the Kirby Project is currently in the development stage. There is a risk that Enerplus’ Kirby Project and/or Joslyn Project, including any future phases or expansions, will not be completed on time or on budget or at all. Additionally, there is a risk that these projects may have delays (or additional delays, with respect to the Joslyn Project) in development or commercial start-up, interruption of operations or increased costs due to many factors, including, without limitation:

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

• breakdown or failure of equipment or processes;

• reservoir performance;

• design, construction, contractor or operator errors that affect operations;

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

• labour disputes, disruptions or declines in productivity;

• increases in materials or labour costs;

• shortages of, or delays in, accessing sufficient numbers of qualified workers and required equipment and services;

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

• changes in project scope;

• disruption delays in the availability of transportation services;

• conditions improved by regulatory approvals;

• violation of permit requirements;

• disruption in the supply of energy;

• delays induced by weather and 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.

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

Given the stage of development of the Kirby Project and the Joslyn Project, various changes to the project scopes and project development plans may be made during implementation of or prior to completing the projects (including, in the case of the Joslyn Project, by Total as the operator of that project). The information contained in this Annual Information Form regarding these projects (including, without limitation, current reserve, resource and economic evaluations) and the development of such projects is conditional upon receipt of all regulatory approvals, the capital requirements of the oilsands projects and Enerplus’ other projects, the continuation of certain economic factors, no material changes being made to the projects or their scope and the overall continuation of the projects as currently planned.

The development of the Kirby Lease and/or the Joslyn Lease 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 to construct or contract with an upgrader to upgrade the quality of the bitumen produced or to be produced by the Kirby Project or the Joslyn Project, and any determination by the operator of the Joslyn Project with respect to an upgrader may or may not include Enerplus' share of production from the Joslyn Project. As a result, there are a number of risks involved in transporting and marketing the bitumen produced from such projects, including securing supplies of diluent 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.

The recovery of bitumen and heavy oil using the SAGD process is subject to a number of risks and uncertainties, many of which are outside of Enerplus’ control.

Current SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas or other fuels in the production of steam which is used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The quality and performance of the reservoir can also impact the timing and levels of production using this technology. Commercial application of this technology for bitumen is relatively new, and accordingly in the absence of long-term operating history there can be no assurances with respect to the sustainability of SAGD operations. Although SAGD technology has been tested in other oil sands operations (including pursuant to pilot tests at the Joslyn Project), there can be no assurance that SAGD utilization on the Joslyn Project or the Kirby Lease will achieve similar results as in other situations or produce bitumen and heavy oil at the expected levels or costs, on schedule or at all. Although Total and Enerplus have conducted a SAGD pilot test on the Joslyn Lease, there can be no assurance that the SAGD operations on the Joslyn Project will produce bitumen and heavy oil at the expected levels or costs, on schedule or at all.

Severe weather conditions can cause reduced production and in some situations result in higher costs. SAGD bitumen recovery facilities and development and expansion of production can entail significant capital outlays. Equipment failures could result in damage to Enerplus’ facilities or wells and liability to third parties against which Enerplus may not be able to fully insure or may elect not to insure because of high premium costs or for other reasons.

If Enerplus’ SAGD facilities do not operate as planned, Enerplus’ revenue, cash flow, earnings and cash distributions may be reduced.

The performance of Enerplus’ SAGD facilities may differ from its expectations. The variances from these expectations may include, without limitation, the ability to operate at the expected level of throughput or production and the reliability or availability of the facilities. Additionally, the operating costs of oil sands projects are significant components of the cost of production of the bitumen. The operating costs of the Enerplus’ oil sands projects may vary considerably during the operating period. If the facilities do not perform to Enerplus’ expectations or as required by regulatory approvals, Enerplus may be required to invest additional capital to correct deficiencies or Enerplus may not be able to produce the expected level of production. If these expectations are not met or operating costs are higher than anticipated, Enerplus’ revenue, cash flow, earnings and cash distributions to the Fund’s unitholders could be reduced.

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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 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.

As a result of the SIFT Tax, Enerplus will effectively be taxed at a level similar to Canadian corporations starting in 2011 (assuming Enerplus does not violate the “normal growth” safe harbour provisions prior to such date). Therefore, Enerplus’ proposed bids for Canadian corporate and property acquisitions may be affected and adjusted for the impact of the SIFT Tax, and Enerplus may not have the same access to capital with respect to corporate and property acquisitions which it has previously experienced. The SIFT Tax 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. One such measure is the “Turning the Corner” plan details announced on March 10, 2007, in which the Canadian federal government proposed new regulations that would require oil sands projects starting operations in 2012 and beyond to reduce greenhouse gas emissions, largely through carbon capture technology. The potential impact on oil sands producers (including Enerplus with respect to its Kirby Project and Joslyn Project) is currently unclear given the draft nature of the regulations and the fact that carbon capture technology has not yet been proven on a large scale, although the cost of implementation of the new measures could be significant. 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. Additionally, in its 2008 provincial budget, the Government of British Columbia proposed a carbon tax and a “cap and trade” system for large emitters of greenhouse gases. 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.

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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 Kirby and Joslyn leases and projects), the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production), and possibly expropriation or cancellation of contract rights. See “Industry Conditions”.

Government regulations may be changed from time to time in response to economic or political conditions. The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase Enerplus’ costs and have a material adverse impact on Enerplus. For example, the Government of Alberta has proposed significant revisions to the royalty regime in place in Alberta. See “Risk Factors  - The proposed new Alberta royalty regime may adversely impact Enerplus and its operations and reserves” and “Industry Conditions  - Royalties and Incentives”.

Although not strictly governmental or regulatory in nature, the implementation of International Financial Reporting Standards to replace Canadian GAAP effective January 1, 2011 (and as a potential reporting alternative to U.S. GAAP or resulting in the elimination of the requirement to reconcile to U.S. GAAP) may have an adverse impact on the Fund’s financial results as reported in its financial statements and may require Enerplus to amend its Credit Facilities to address the changes in accounting principles.

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 oil and 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. Pipeline and transportation constraints experienced by oil producers in Montana, North Dakota and southeast Saskatchewan have become more pronounced as a result of strong crude oil prices and the increased drilling and development activities in these areas. If these constraints remain unresolved, Enerplus’ ability to transport its crude oil production in these regions may be impaired and could adversely impact Enerplus’ production volumes from these areas. Growing oil and natural gas production from western Canada is also increasing the risks of access constraints on export pipelines. 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 Kirby Project and 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.

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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;

• weather-related delays such as freeze-offs, flooding and premature thawing;

• 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 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.

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

Under Canadian GAAP, 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, 2007. 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 changed or interpreted in a manner which is detrimental to Enerplus’ operations and financial structure, and therefore the Fund’s unitholders.

Changes to Taxation of Income Trusts

On June 22, 2007, the legislation to implement the SIFT Tax received Royal Assent and became law. See “General Development of Enerplus Resources Fund  - Developments in the Past Three Years  - Changes to Taxation of Income Trusts”. Enerplus expects that the implementation of the SIFT Tax will result in adverse tax consequences to Enerplus and certain unitholders (including most particularly Enerplus unitholders that are tax deferred or non-residents of Canada) and may impact the level of cash distributions from the Fund to its unitholders. In particular:

• the Fund will 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 ability of the Fund to pay monthly cash distributions or the amount of cash distributions available to its unitholders;

• the estimated net present value of future net revenues, on an after-tax basis, from Enerplus’ oil, NGLs, natural gas reserves and bitumen reserves may be decreased as a result of the application of taxes to which Enerplus has historically not been subject; and

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

Management of Enerplus believes that the SIFT Tax has reduced, and may further reduce, the value of the Trust Units, which may increase the cost to the Fund of raising capital in the public capital markets. In addition, management of Enerplus believes that the SIFT Tax: (a) has substantially, if not completely, eliminated any competitive advantage that the Fund and other Canadian energy trusts have enjoyed relative to their corporate peers in raising capital in a tax efficient manner; and (b) may place the Fund and other Canadian energy trusts at a competitive disadvantage relative to certain of their industry competitors, including non-taxable pension entities and U.S. master limited partnerships and limited liability companies, which will continue to not be subject to entity level taxation. The SIFT Tax may also make the Trust Units less attractive as consideration for acquisitions in the future. As a result, it may become more difficult for Enerplus to compete effectively for acquisition opportunities. There can be no assurance that Enerplus will be able to generate sufficient tax pools and/or reorganize its legal and tax structure in order to mitigate, in whole or in part, the expected impact of the SIFT Tax. Furthermore, the combination with Focus may reduce the amount of tax pool coverage, on an aggregate basis, and may adversely impact Enerplus’ tax position after 2010 as compared to Enerplus’ existing tax pool coverage.

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Additionally, as described under “General Development of Enerplus Resources Fund  - Developments in the Past Three Years  - Changes to Taxation of Income Trusts”, any “undue expansion” beyond certain “normal growth” parameters could result in the transition period being terminated with the loss of the benefit to the Fund of that transitional period. As a result, the adverse tax consequences resulting from the SIFT Tax could be borne sooner than January 1, 2011.

While these guidelines are such that it is unlikely they would affect Enerplus’ ability to raise the capital required to maintain and grow Enerplus’ existing operations in the ordinary course during the transition period, they are expected to adversely affect Enerplus’ ability to undertake significant acquisitions. Furthermore, the guidelines, which are incorporated by reference into the statute, may be amended from time to time, and may be amended without an Act of the Canadian Parliament. 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 SIFT Tax 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 there is a time when it is 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 that time, “all or substantially all” of the trust’s property consisted of property other than taxable Canadian property (the “TCP Exception”). Based on the most recent information obtained by Enerplus through its transfer agent and financial intermediaries, in February 2008 (prior to completion of the Focus acquisition) an estimated 74% of the Fund’s issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act). 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 have a specific limit on the percentage of Trust Units that may be owned by non-residents.

However, 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”.

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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 and anticipates 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  - Changes to Taxation of 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.

• 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”), registered disability savings plans (“RDSPs”) or deferred profit sharing plans (“DPSPs”). If, at the end of any month, one of these exempt plans (other than an RDSP) 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, RRIF or RDSP 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. If an RDSP holds non-qualified Trust Units it must pay a tax equal to 50% of the value of the Trust Units at the time they ceased to be qualified investments.

• 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 statutory “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.

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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 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.

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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 2007 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 2006, and Enerplus does not expect to be considered a PFIC for 2007 or 2008.

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.

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

The 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”.

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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. On March 24, 2007, Bill 1672 was introduced into the U.S. House of Representatives which, if enacted as presented, would make dividends from Canadian income funds such as the Fund ineligible for treatment as a “Qualified Dividend”, and a comparable Bill was introduced in the U.S. Senate. The dividend would then become “non-qualified dividends from a foreign corporation” subject to the normal rates of tax commencing with dividends received after the date of enactment. The proposed bill still requires the approval of the House of Representatives, the Senate and the President prior to it being enacted. Therefore, it is uncertain as to if or when the bill will be enacted, or if it will be enacted as presented.

Furthermore, the changes to the Tax Act relating to the SIFT Tax, such as the recharacterization of trust distributions as corporate dividends, could have unexpected effects on the taxation of cash distributions or other property paid by the Fund to unitholders who are not residents of Canada. These effects may vary depending upon the laws of the relevant foreign jurisdiction and the terms of any applicable tax treaty between Canada and the country in which a particular unitholder resides. See “Risk Factors  - Risks Related 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 and the NYSE in 2007.

	TSX						NYSE
Month	High		Low		Volume		High		Low		Volume
January	$	51.86	$	46.50		6,791,615	US$	44.10	US$	39.53		6,346,900
February		52.99		49.78		4,827,961		44.67		42.60		3,482,400
March		51.00		47.01		6,373,107		43.78		40.00		4,176,800
April		49.36		47.75		6,127,105		43.85		41.63		3,865,300
May		52.90		48.15		10,628,924		48.99		43.50		5,435,400
June		53.70		47.50		8,693,317		50.75		44.30		4,261,900
July		51.85		45.93		15,705,816		48.96		43.05		4,555,400
August		47.70		41.00		8,135,503		44.55		38.11		5,625,800
September		47.67		44.52		6,642,598		47.68		42.20		3,415,500
October		47.40		44.08		6,279,476		48.57		44.88		3,587,200
November		46.22		39.33		7,087,140		49.19		39.40		4,046,200
December		40.71		38.00		9,605,864		41.35		38.06		5,393,700

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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. The board of directors of EnerMark is in the process of reviewing the composition of its committees following the recent additions of Robert B. Hodgins, David P. O’Brien and Clayton H. Woitas to the board of directors and because Robert L. Normand will not be standing for re-election to the board of directors at the annual general and special meeting of the Fund’s unitholders to be held on May 9, 2008.

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).
Robert B. Hodgins Calgary, Alberta, Canada	December 2007	Independent businessman since November 2004. Prior thereto, Chief Financial Officer of Pengrowth Energy Trust (a TSX and NYSE-listed energy trust).
Gordon J. Kerr 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) St. Colombam, Québec, Canada	March 1998	Corporate director.
David P. O’Brien(9) Calgary, Alberta, Canada	March 2008	Corporate director, including Chairman of EnCana Corporation (a TSX and NYSE-listed oil and gas company) since April 2002 and Chairman of the Royal Bank of Canada (a TSX and NYSE-listed Canadian chartered bank) since February 2004.
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).
Clayton H. Woitas Calgary, Alberta, Canada	March 2008	President of Range Royalty Management Ltd. (a private energy company) since June 2006. Prior thereto, Chairman and Chief Executive Officer of Profico Energy Management Ltd. (a private oil and gas company).
Robert L. Zorich(3)(6)(10) 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).

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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 Health,  Safety & Environment 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 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. Until May 9, 2007, Mr. Normand was a director of Quebecor World Inc. On January 21, 2008, Quebecor World filed for and obtained an order for creditor protection under the CCAA.

(9) Mr. O’Brien was a director of Air Canada in April 2003 when Air Canada filed for protection under the CCAA. Mr. O’Brien resigned as a director from Air Canada in November 2003.

(10) 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.

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
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.
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.
Robert J. Waters Calgary, Alberta, Canada	Senior Vice President & Chief Financial Officer	Senior Vice President & Chief Financial Officer of Enerplus.

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Name and Residence	Office	Principal Occupation for Past Five Years
Jo-Anne M. Caza Calgary, Alberta, Canada	Vice President, Investor Relations and Corporate Communications	Vice President, Investor Relations and Corporate Communications since January 2008. Prior thereto, Vice President, Investor Relations of Enerplus.
Raymond J. Daniels Calgary, Alberta, Canada	Vice President, Oil Sands	Vice President, Oil Sands of Enerplus since December 2007. Prior thereto, Vice President, Surmont Development with ConocoPhillips Canada.
Rodney D. Gray Calgary, Alberta, Canada	Vice President, Finance	Vice President, Finance of Enerplus since February 2005. Prior thereto, Controller, Finance of Enerplus.
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).
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.
Daniel M. Stevens Crossfield, Alberta, Canada	Vice President, Development Services	Vice President, Development Services 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.).

Trust Unit Ownership

As of March 7, 2008, the directors and officers named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 568,304 Trust Units, representing approximately 0.35% of the outstanding Trust Units as of that date, and 4,361,866 Focus Exchangeable LP Units, representing approximately 48% of the outstanding Focus Exchangeable LP Units as of that date. In the aggregate, such securities represent approximately 1.48% of the aggregate voting securities of the Fund.

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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. 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. Mr. David P. O’Brien, a director of EnerMark, is Chairman of the Royal Bank of Canada, which is a lender to EnerMark and whose investment banking affiliate, RBC Capital Markets, provides investment banking and financial advisory services to Enerplus from time to time. Mr. Clayton H. Woitas, a director of EnerMark, is a director, officer and significant securityholder in Range Royalty Limited Partnership, which owns gross overriding royalty interests on certain properties owned by Enerplus, including certain properties acquired as a result of Enerplus’ acquisition of Focus on February 13, 2008.

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, 2005 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 Bank Credit Facility (including all amendments thereto) and a form of each series of Senior Unsecured Notes (including all amendments thereto) was filed on March 18, 2008 as a “Material document” on the Fund’s SEDAR profile at www.sedar.com and on Form 6-K on EDGAR at www.sec.gov.

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 and on EDGAR at www.sec.gov on December 10, 2007. 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 “Corporate Governance”. A draft of the proposed Amended and Restated Unit Rights Plan Agreement, which is being submitted for approval by the Fund’s unitholders at the annual general and special meeting of the Fund’s unitholders to be held on May 9, 2008 (the “AGM”), is also available on the Fund’s website as noted above. If such plan is not approved at the AGM, the Unitholder Rights plan will terminate and cease to be in effect.

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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. NSAI prepared the NSAI 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 NSAI Report, the designated professionals of NSAI, as a group, beneficially owned, directly or indirectly, less than 1% of the Fund’s outstanding Trust Units. GLJ prepared each of the GLJ Reserves Report in respect of the SAGD reserves attributable to Enerplus’ interest in the Joslyn Project and the GLJ Oil Sands Resources Report in respect of the contingent and prospective bitumen resources attributable to the Kirby Lease and Enerplus’ working interest in the Joslyn Project (together with interests in certain minor non-operated oil sands projects). Summaries in respect of the Kirby Lease and the Joslyn Project are contained in this Annual Information Form. As of the dates of each of the GLJ Reserves Report and the GLJ Oil Sands 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. Paddock prepared the Paddock Focus Report in respect of the oil and natural gas reserves of Focus (which was acquired by Enerplus on February 13, 2008), a summary of which is contained in this Annual Information Form. As of the date of the Paddock Focus Report, the designated professionals of Paddock, 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 in Canada is CIBC Mellon Trust Company, at its principal offices in Calgary, Alberta, Toronto, Ontario and Montréal, Québec. The U.S. co-transfer agent for the Trust Units is Mellon Investor Services LLC in New York, New York. At the annual general and special meeting of the Fund’s unitholders to be held on May 9, 2008, the Fund’s unitholders will be asked to approve an extraordinary resolution to remove CIBC Mellon Trust Company as Trustee of the Fund and appoint Computershare Trust Company of Canada to replace CIBC Mellon Trust Company as Trustee of the Fund. If such resolution is approved, Computershare Trust Company of Canada at its principal offices in Calgary, Alberta and Toronto, Ontario will replace CIBC Mellon Trust Company of Canada as registrar and transfer agent for the Trust Units in Canada, and Computershare Trust Company N.A. at its principal offices in Golden, Colorado will act as transfer agent for the Trust Units in the United States.

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 13, 2008 for its 2008 annual general and special 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, 2007. 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.

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APPENDIX “A”

REPORT ON RESERVES DATA BY INDEPENDENT

QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in CSA Staff Notice 51-324  - Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities, 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, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.

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, 2007, 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	Evaluation of the P&NG Reserves in Canada of Enerplus Resources Fund, As of December 31, 2007, prepared July 2007 to January 2008	Canada	Nil	$	4,286	$	378	$	4,664

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. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

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Executed as to our report referred to above:

Sproule Associates Limited Calgary, Alberta February 15, 2008	“Robert R. Warholm” Robert R. Warholm, P. Eng. Manager, Engineering
	“Michael W. Maughan” Michael W. Maughan Vice-President, Geoscience
	“R. Keith MacLeod” R. Keith MacLeod President

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APPENDIX “B”

REPORT ON RESERVES DATA BY INDEPENDENT

QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in CSA Staff Notice 51-324  - Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities, 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 for the Joslyn Creek property as at December 31, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.

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, 2007, 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	January 9, 2008	Canada		-	$	144,001		-	$	144,001

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. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 28, 2008

“Dana B. Laustsen”

Dana B. Laustsen, P. Eng.

Executive Vice-President

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APPENDIX “C”

REPORT ON RESERVES DATA BY INDEPENDENT

QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in CSA Staff Notice 51-324  - Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities, 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, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.

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 reserve 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 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2007, 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 (before U.S. federal income taxes, 10% discount rate)
Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated		Reviewed	Total
			(in $ thousands)
Netherland, Sewell & Associates, Inc.	Estimate of Reserves and Future Revenue to the Enerplus Resources (USA) Corporation Interest as of December 31, 2007, dated February 21, 2008	Montana, North Dakota and Wyoming, USA	Nil	$	1,049,290.9	Nil	$	1,049,290.9

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 our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Executed as to our report referred to above:

NETHERLAND, SEWELL & ASSOCIATES, INC.

Dallas, Texas, USA

March 5, 2008

/s/ C.H. (SCOTT) REES III, P.E.

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

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APPENDIX “D”

REPORT OF MANAGEMENT AND DIRECTORS

ON RESERVES DATA AND OTHER INFORMATION

Terms to which a meaning is described in CSA Staff Notice 51-324  - Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities 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 are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.

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 Form 51-101F1 containing reserves data and other oil and gas information;

(b) the filing of Forms 51-102F2 which are the reports of the independent qualified reserves evaluators on the reserves data; and

(c) the content and filing of this report.

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Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

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, 2008

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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 current 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. The board of directors of EnerMark is in the process of reviewing the composition of the Committee as Mr. Normand will not be standing for re-election to the board of directors of EnerMark at the annual general and special meeting of the Fund’s unitholders to be held May 9, 2008.

C. Relevant Education and Experience

Name (Director Since)

Principal Occupation and Biography

Mr. Robert L. Normand (DSC, C.A.) (March 1998) Other Public Directorships •  Aurizon Mines Ltd. (gold mining) •  ING Canada Inc. (property and casualty insurance)

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.

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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 as 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. In addition to serving as a director of the public entities listed herewith, Mr. Roane is the Chairman of the board of directors of Flexpipe Systems Inc. and a director of Tarpon Energy Services Ltd., both of which are private energy services companies. Mr. Roane is also a member of the Alberta Securities Commission. 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 Magellan Resources Ltd., a private oil and gas company. 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 2007 and 2006 were pre-approved by the Committee. Based on the Committee’s discussions with management and the independent auditors, the Committee is of the view that the provision of the non-audit services by Deloitte & Touche LLP described above is compatible with maintaining that firm’s independence from the Fund.

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E. External Auditor Service Fees

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

	2007		2006
	(in $ thousands)
Audit fees(1)	$	751.4	$	763.9
Audit-related fees(2)		-		-
Tax fees(3)		132.6		1,211.3
All other fees(4)		-		-
	$	884.0	$	1,975.2

Notes:

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

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

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

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

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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;

(g) have a private meeting with the external auditors at every quarterly Committee meeting;

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(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;

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12. Review with management the Fund’s internal controls, and evaluate whether the Fund is operating in accordance with prescribed policies and procedures;

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 our conventional crude oil and natural gas operations including our SAGD-recoverable bitumen activities related to the Joslyn Project. The Proved Reserves using constant prices and costs 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 oil, natural gas, natural gas liquids and bitumen 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, 2007, 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 crude oil, natural gas, natural gas liquids and bitumen reserves are located in western Canada, primarily in Alberta, British Columbia, Saskatchewan and Manitoba, as well as in Montana, North Dakota and Wyoming in the United States. The Fund’s net Proved Reserves summarized in the following 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:

F-1

	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)			(MMcf)			(Mbbls)
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
Purchases of reserves in place		4			2,851			-			124			13,311			128			16,162			-
Sales of reserves in place		-			(2,587	)		-			-			-			-			(2,587	)		-
Discoveries and extensions		1,411			18,387			-			-			-			1,411			18,387			-
Revisions of previous estimates		(275	)		3,931			35			292			6,193			17			10,124			35
Improved recovery		2,387			6,676			-			5,744			4,722			8,131			11,398			-
Production		(8,680	)		(72,262	)		-			(3,031	)		(3,435	)		(11,711	)		(75,697	)		-
Proved Developed and Undeveloped Reserves at December 31, 2007		96,145			674,457			8,424			22,598			33,129			118,743			707,586			8,424
Proved Developed Reserves
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
December 31, 2007		90,715			533,654			2,341			19,707			26,839			110,422			560,493			2,341

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:

	2007			2006			2005
	(in $ thousands)
Capitalized costs(1)	$	5,245,528		$	4,689,444		$	4,141,627
Less accumulated depletion, depreciation and amortization		(1,970,467	)		(1,608,186	)		(1,212,145	)
Net capitalized costs	$	3,275,061		$	3,081,258		$	2,929,482

Note:

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

F-2

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, 2007
	Canada		United States		Total
	(in $ thousands)
Acquisition of properties:
Proved	$	10,215	$	60,954	$	71,169
Unproved		212,154		915		213,069
Exploration costs		33,994		13,770		47,764
Development costs		231,889		91,557		323,446
Asset retirement costs		52,179		262		52,441
	$	540,431	$	167,458	$	707,889

	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(1)		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

Note:

(1) The Fund commenced oil and gas producing activities in the United States on August 30, 2005.

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 gas 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.

F-3

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, 2007, 2006 and 2005.

	For the Year Ended December 31, 2007
	Canada		United States		Total
	(in $ thousands)(1)
Revenue
Sales(2)	$	1,025,822	$	228,183	$	1,254,005
Deduct
Production Costs(3)		286,248		10,000		296,248
Depletion, depreciation, amortization, accretion and impairment		299,217		103,752		402,969
Current and Deferred income tax provision		70,827		30,204		101,031
Results of operations for oil and gas producing activities	$	369,530	$	84,227	$	453,757

	For the Year Ended December 31, 2006
	Canada			United States		Total
	(in $ thousands)(1)
Revenue
Sales(2)	$	1,079,251		$	219,519	$	1,298,770
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 (recovery)		(55,409	)		19,845		(35,564	)
Results of operations for oil and gas producing activities	$	572,192		$	81,085	$	653,277

	For the Year Ended December 31, 2005
	Canada		United States(4)		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

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 commenced oil and gas producing activities in the United States on August 30, 2005.

F-4

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 crude oil, natural gas and SAGD bitumen reserves.

	As at December 31, 2007
	Canada		United States		Total
	(in $ millions)
Future cash inflows	$	11,520	$	2,035	$	13,555
Future production costs		3,776		297		4,073
Future development and asset retirement costs		587		75		662
Future income tax expenses		1,058		427		1,485
Future net cash flows	$	6,099	$	1,236	$	7,335
Deduction: 10% annual discount factor		2,818		527		3,345
Standardized measure of discounted future net cash flows	$	3,281	$	709	$	3,990

	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

	As at December 31, 2005
	Canada		United States(1)		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

Note:

(1) The Fund commenced oil and gas producing activities in the United States on August 30, 2005.

F-5

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:

	2007			2006			2005
	(in $ millions)
Beginning of year	$	3,578		$	5,406		$	2,934
Sales of oil and natural gas produced, net of production costs		(972	)		(1,028	)		(1,009	)
Net changes in sales prices and production costs		1,197			(1,963	)		2,170
Changes in previously estimated development costs incurred during the period		145			240			113
Changes in estimated future development costs		(221	)		(210	)		(308	)
Extension, discoveries and improved recovery, net of related costs		416			725			424
Purchase of reserves in place		42			31			952
Sales of reserves in place		(4	)		(3	)		(30	)
Net change resulting from revisions in previous quantity estimates		(8	)		(130	)		126
Accretion of discount		312			442			230
Net change income taxes		(496	)		68			(196	)
End of year	$	3,990		$	3,578		$	5,406

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.

F-6

APPENDIX “G”

INFORMATION REGARDING FOCUS ENERGY TRUST

Enerplus Acquisition of Focus

On February 13, 2008, the Fund completed its acquisition of Focus pursuant to a plan of arrangement under the Business Corporations Act (Alberta). Pursuant to the arrangement, the Fund acquired all of the assets and assumed all of the liabilities of Focus, Focus unitholders received 0.425 of an Enerplus Trust Unit for each Focus trust unit, and all of the trust units of Focus were redeemed. The Fund issued an aggregate of 30,149,752 Trust Units to former Focus unitholders in the transaction.

The holders of Focus Exchangeable LP Units did not exchange their Focus Exchangeable LP Units for Enerplus Trust Units pursuant to the arrangement, but following the arrangement the Focus Exchangeable LP Units are exchangeable for Enerplus Trust Units on the basis of 0.425 of an Enerplus Trust Unit for each Focus Exchangeable LP Unit, and the voting rights attached to and cash distributions and payments made on the Focus Exchangeable LP Units have been similarly adjusted in accordance with such exchange ratio.

As a result of the arrangement, Enerplus acquired all of Focus’ oil and natural gas properties and assets and related facilities. A description of Focus’ properties and assets, including the reserves data and other oil and gas information in respect of such properties as at and for the year ended December 31, 2007, is set forth below.

Updated Organizational Structure of Enerplus Following Focus Acquisition

The simplified organizational structure of Enerplus following its acquisition of Focus effective February 13, 2008, 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:

G-1

Combined Oil and Natural Gas Reserves of Enerplus and Focus

The following table sets out the combined oil and natural gas reserves of Enerplus and Focus as at December 31, 2007, on a company interest basis, as if Enerplus’ February 13, 2008 acquisition of Focus had been completed prior to December 31, 2007. The combined information is presented as supplemental information only. The reserves information is the compilation of Enerplus’ aggregate reserves set forth under “Oil and Natural Gas Reserves” in this Annual Information Form (as evaluated or reviewed by Sproule, GLJ and NSAI) and Focus’ reserves set forth in this Appendix “G” (as evaluated by Paddock). The combined information set forth below is subject to the same qualifications and advisories that apply to the separate Enerplus and Focus reserves disclosure set forth elsewhere in this Annual Information Form.

Summary of Combined Enerplus and Focus Oil and Natural Gas Reserves

as of December 31, 2007

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
Enerplus Canada		63,963		28,832		2,365		95,160		10,469		649,382		213,860
Enerplus United States		21,672		-		-		21,672		74		28,527		26,501
Total Enerplus		85,635		28,832		2,365		116,832		10,543		677,909		240,361
Focus Energy Trust		3,500		-		-		3,500		1,774		196,111		37,959
Total Combined Enerplus + Focus		89,135		28,832		2,365		120,332		12,317		874,020		278,320
Proved developed non-producing
Enerplus Canada		190		-		-		190		510		14,911		3,185
Enerplus United States		1,588		-		-		1,588		5		1,623		1,863
Total Enerplus		1,778		-		-		1,778		515		16,534		5,048
Focus Energy Trust		-		-		-		-		15		1,705		299
Total Combined Enerplus + Focus		1,778		-		-		1,778		530		18,239		5,347
Proved undeveloped
Enerplus Canada		3,233		2,383		6,203		11,819		694		164,829		39,984
Enerplus United States		3,377		-		-		3,377		33		6,805		4,544
Total Enerplus		6,610		2,383		6,203		15,196		727		171,634		44,528
Focus Energy Trust		127		-		-		127		956		142,830		24,888
Total Combined Enerplus + Focus		6,737		2,383		6,203		15,323		1,683		314,464		69,416
Total Proved
Enerplus Canada		67,386		31,215		8,568		107,169		11,673		829,122		257,029
Enerplus United States		26,637		-		-		26,637		112		36,955		32,908
Total Enerplus		94,023		31,215		8,568		133,806		11,785		866,077		289,937
Focus Energy Trust		3,627		-		-		3,627		2,745		340,646		63,146
Total Combined Enerplus + Focus		97,650		31,215		8,568		137,433		14,530		1,206,723		353,083
Probable
Enerplus Canada		17,837		10,948		54,930		83,715		3,797		308,276		138,891
Enerplus United States		6,719		-		-		6,719		30		27,938		11,406
Total Enerplus		24,556		10,948		54,930		90,434		3,827		336,214		150,297
Focus Energy Trust		939		-		-		939		834		118,948		21,598
Total Combined Enerplus + Focus		25,495		10,948		54,930		91,373		4,661		455,162		171,895
Total Proved plus Probable
Enerplus Canada		85,223		42,163		63,498		190,884		15,470		1,137,398		395,920
Enerplus United States		33,356		-		-		33,356		142		64,893		44,314
Total Enerplus		118,579		42,163		63,498		224,240		15,612		1,202,291		440,234
Focus Energy Trust		4,566		-		-		4,566		3,579		459,594		84,744
Total Combined Enerplus + Focus		123,145		42,163		63,498		228,806		19,191		1,661,885		524,978

G-2

Summary of Combined Enerplus and Focus Net Present Value

of Future Net Revenue Attributable to Oil and Gas Reserves

as of December 31, 2007

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%			Unit Value(1)
	(in $ millions)																					$/BOE
CONVENTIONAL OIL AND GAS RESERVES
Proved Developed Producing
Enerplus Canada		7,365		4,669		3,514		2,869		2,451		6,359		4,204		3,248		2,698		2,333		$	19.80
Enerplus United States		1,296		933		738		618		537		957		686		539		448		387		$	33.08
Total Enerplus		8,661		5,602		4,252		3,487		2,988		7,316		4,890		3,787		3,146		2,720		$	21.29
Focus Energy Trust		1,132		905		758		656		580		1,009		822		699		612		547		$	22.87
Total Combined Enerplus + Focus		9,793		6,507		5,010		4,143		3,568		8,325		5,712		4,486		3,758		3,267		$	21.51
Proved Developed Non-Producing
Enerplus Canada		92		58		42		33		26		75		49		36		27		24		$	17.20
Enerplus United States		95		69		53		43		36		57		42		31		26		20		$	34.11
Total Enerplus		187		127		95		76		62		132		91		67		53		44		$	23.80
Focus Energy Trust		5		4		3		3		3		4		4		3		3		2		$	15.77
Total Combined Enerplus + Focus		192		131		98		79		65		136		95		70		56		46		$	23.38
Proved Undeveloped
Enerplus Canada		640		393		251		162		104		549		332		209		132		79		$	8.67
Enerplus United States		187		119		83		61		47		121		74		50		35		26		$	21.04
Total Enerplus		827		512		334		223		151		670		406		259		167		105		$	10.15
Focus Energy Trust		480		313		213		148		103		407		268		182		126		87		$	9.78
Total Combined Enerplus + Focus		1,307		825		547		371		254		1,077		674		441		293		192		$	10.00
Total Proved
Enerplus Canada		8,097		5,120		3,807		3,064		2,581		6,983		4,585		3,493		2,857		2,436		$	18.23
Enerplus United States		1,578		1,121		874		722		620		1,135		802		620		509		433		$	31.44
Total Proved Conventional Reserves, Enerplus		9,675		6,241		4,681		3,786		3,201		8,118		5,387		4,113		3,366		2,869		$	19.78
Focus Energy Trust		1,617		1,221		975		807		686		1,421		1,093		884		741		636		$	17.67
Total Proved Conventional Reserves, Combined Enerplus + Focus		11,292		7,462		5,656		4,593		3,887		9,539		6,480		4,997		4,107		3,505		$	19.38
Probable
Enerplus Canada		3,195		1,452		857		582		430		2,446		1,133		681		472		353		$	12.25
Enerplus United States		610		288		175		125		97		392		181		108		74		57		$	18.24
Total Probable Conventional Reserves, Enerplus		3,805		1,740		1,032		707		527		2,838		1,314		789		546		410		$	12.97
Focus Energy Trust		653		394		264		189		143		487		297		201		146		111		$	13.85
Total Probable Conventional Reserves, Combined Enerplus + Focus		4,458		2,134		1,296		896		670		3,325		1,611		990		692		521		$	13.14
Total Proved Plus Probable Conventional Reserves, Enerplus		13,480		7,981		5,713		4,493		3,728		10,956		6,701		4,902		3,912		3,279		$	18.07
Total Proved Plus Probable Conventional Reserves, Focus		2,269		1,615		1,238		996		829		1,909		1,390		1,086		886		746		$	16.69
Total Proved Plus Probable Conventional Reserves, Combined Enerplus + Focus		15,749		9,596		6,951		5,489		4,557		12,865		8,091		5,988		4,798		4,025		$	17.81
BITUMEN RESERVES (ENERPLUS ONLY)
Proved Developed Producing		35		28		23		19		16		28		22		19		15		13		$	9.63
Proved undeveloped		100		56		32		19		11		72		40		22		13		7		$	5.63
Total Proved Bitumen Reserves		135		84		55		38		27		100		62		41		28		20		$	6.79
Probable Bitumen Reserves		1,293		294		89		29		6		928		207		59		15		(1	)	$	1.84
Total Proved Plus Probable Bitumen Reserves		1,428		378		144		67		33		1,028		269		100		43		19		$	2.55
TOTAL ENERPLUS AND FOCUS RESERVES		17,177		9,974		7,095		5,556		4,590		13,893		8,360		6,088		4,841		4,044		$	15.88

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

G-3

Oil and Natural Gas Reserves of Focus

Summary of Oil and Natural Gas Reserves of Focus

All of the reserves attributable to the Focus Properties have been evaluated by Paddock, a firm of independent petroleum engineers based in Calgary, Alberta, in accordance with NI 51-101 using the same forecast price, inflation and exchange rate assumptions utilized by Sproule (Enerplus’ Canadian conventional oil and gas independent evaluators), for consistency within Enerplus reserves reporting. The Paddock Focus Report is effective December 31, 2007.

The following sections and tables summarize, as at December 31, 2007, the 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 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 the Focus Properties are located in Canada. In all of the reserves data, minor amounts of heavy oil have been included with light and medium oil. On a proved plus probable basis, the total amount of heavy oil represents less than one percent of total corporate reserves and future net revenues discounted at ten percent.

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. The Canadian federal government has implemented the SIFT Tax which is designed to generally tax income trusts at the same effective tax rates as Canadian corporations, effective for the 2011 tax year, and the after-tax estimates of the net present value of future net revenue from the reserves include the estimated impact of the SIFT Tax on Focus as at December 31, 2007. Additionally, as the proposed amendments to the Province of Alberta’s royalty regime announced in October 2007 have not yet been passed into law and may be subject to further revision, the estimated net present value of future net revenues attributable to Focus’ reserves are based upon the existing Alberta royalty regime and do not give effect to the proposed changes. For additional information, see “General Development of Enerplus Resources Fund  - Developments in the Past Three Years”, “Operational Information  - Tax Horizon”, “Industry Conditions” 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 transportation. 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 the crude oil, NGLs and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in “Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information” in conjunction with the following tables and notes. Columns may not add due to rounding.

G-4

Summary of Oil and Gas Reserves

As of December 31, 2007

Forecast Prices and Costs

	OIL AND NATURAL GAS RESERVES
	Light & Medium Oil						Natural Gas						Natural Gas Liquids						Total
RESERVES CATEGORY	Company Interest		Gross		Net		Company Interest		Gross		Net		Company Interest		Gross		Net		Company Interest		Gross		Net
	(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)		(MMcf)		(MMcf)		(Mbbls)		(Mbbls)		(Mbbls)		(MBOE)		(MBOE)		(MBOE)
Proved Developed Producing		3,500		3,493		3,042		196,111		196,093		172,417		1,774		1,774		1,367		37,959		37,949		33,145
Proved Developed Non-Producing		-		-		-		1,705		1,705		1,264		15		15		10		299		299		221
Proved Undeveloped		127		127		115		142,830		142,830		125,550		956		956		755		24,888		24,888		21,795
Total Proved Reserves		3,627		3,620		3,157		340,646		340,628		299,231		2,745		2,745		2,132		63,146		63,136		55,161
Probable Reserves		939		937		828		118,948		118,940		105,410		834		833		654		21,598		21,593		19,050
Total Proved Plus Probable		4,566		4,557		3,985		459,594		459,568		404,641		3,579		3,578		2,786		84,744		84,730		74,211

Summary of Net Present Value of Future Net Revenue

Attributable to Oil and Gas Reserves

As of December 31, 2007

Forecast Prices and Costs

	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR)
	Before Deducting Income Taxes, Discontinued at (%/Year)										After Deducting Income Taxes, Discontinued at (%/Year)
RESERVES CATEGORY	0%		5%		10%		15%		20%		0%		5%		10%		15%		20%		Unit Value(1)
	(in $ millions)																				($/BOE)
Proved Developed Producing		1,132		905		758		656		580		1,009		822		699		612		547	$	22.87
Proved Developed Non-Producing		5		4		3		3		3		4		4		3		3		2	$	15.77
Proved Undeveloped		480		313		213		148		103		407		268		182		126		87	$	9.78
Total Proved Reserves		1,617		1,221		975		807		686		1,421		1,093		884		741		636	$	17.67
Probable Reserves		653		394		264		189		143		487		297		201		146		111	$	13.85
Total Proved Plus Probable		2,269		1,615		1,238		996		829		1,909		1,390		1,086		886		746	$	16.69

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

Summary of Oil and Gas Reserves

As of December 31, 2007

Constant Prices and Costs

	OIL AND NATURAL GAS RESERVES
	Light & Medium Oil						Natural Gas						Natural Gas Liquids						Total
RESERVES CATEGORY	Company Interest		Gross		Net		Company Interest		Gross		Net		Company Interest		Gross		Net		Company Interest		Gross		Net
	(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)		(MMcf)		(MMcf)		(Mbbls)		(Mbbls)		(Mbbls)		(MBOE)		(MBOE)		(MBOE)
Proved Developed Producing		3,504		3,497		3,047		195,943		195,925		172,360		1,774		1,774		1,367		37,935		37,925		33,141
Proved Developed Non-Producing		-		-		-		1,697		1,697		1,258		15		15		10		298		298		220
Proved Undeveloped		127		127		115		142,803		142,803		125,716		956		956		754		24,884		24,884		21,822
Total Proved Reserves		3,631		3,624		3,162		340,443		340,425		299,334		2,745		2,745		2,131		63,117		63,107		55,182
Probable Reserves		942		940		831		118,606		118,598		105,178		834		833		654		21,544		21,539		19,015
Total Proved Plus Probable Reserves		4,573		4,564		3,993		459,049		459,023		404,512		3,579		3,578		2,785		84,660		84,646		74,197

G-5

Summary of Net Present Value of Future Net Revenue

Attributable to Oil and Gas Reserves

As of December 31, 2007

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%		Unit Value(1)
	(in $ millions)																				($/BOE)
Proved Developed Producing		1,045		847		717		624		556		943		777		666		587		527	$	21.63
Proved Developed Non-Producing		5		4		3		3		2		4		3		3		3		2	$	14.62
Proved Undeveloped		365		235		156		104		68		319		207		137		91		58	$	7.16
Total Proved Reserves		1,414		1,086		876		731		626		1,266		987		807		680		587	$	15.88
Probable Reserves		512		319		219		159		121		385		243		168		123		95	$	11.51
Total Proved Plus Probable Reserves		1,926		1,405		1,095		891		747		1,651		1,230		975		803		682	$	14.76

Note:

(1) Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year. The unit values are based on net reserves volumes.

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(1)			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)
2008		89.61			88.17			54.67			75.83			6.51			7.56			52.29			65.72			90.30			2.0			1.00
2009		86.01			84.54			52.42			72.71			7.22			8.27			50.14			63.01			86.58			2.0			1.00
2010		84.65			83.16			51.56			71.52			7.69			8.74			49.32			61.98			85.17			2.0			1.00
2011		82.77			81.26			50.38			69.89			7.70			8.75			48.20			60.57			83.23			2.0			1.00
2012		82.26			80.73			50.05			69.43			7.61			8.66			47.88			60.17			82.68			2.0			1.00
Thereafter			(2)			(2)			(2)			(2)			(2)		+2.0	%			(2)			(2)			(2)			(2)		1.00

Notes:

(1) Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

(2) Escalation varies after 2012.

In 2007, Focus received a weighted average price (net of transportation costs but before hedging) of $71.12/bbl for light and medium crude oil, $63.36/bbl for NGLs and $6.45/Mcf for natural gas.

G-6

Constant Prices and Costs

The constant price and cost case assumes the continuance of product prices at December 31, 2007 and operating costs projected for 2008, 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, 2007 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(1)

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

96.00

93.44

41.70

72.58

6.52

6.80

61.75

81.79

95.59

-

1.009

Notes:

(1) Edmonton refinery postings for 40o API, 0.4% sulphur content crude oil.

Undiscounted Future Net Revenue by Reserves Category

The undiscounted total future net revenue by reserves category as of December 31, 2007, using 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)
Proved Reserves		3,098		411		738		281		51		1,617		196		1,421
Probable Reserves		1,168		146		294		67		9		652		164		488
Proved Plus Probable Reserves		4,266		557		1,032		348		60		2,269		360		1,909

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, 2007, using forecast prices and costs and discounted at 10% per year, is set forth below:

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (Discounted at 10%/year)		Unit Value(3)
		(in $ millions)		($/Bbl/$/Mcf)
Proved Reserves	Light and Medium Crude Oil(1) Natural Gas(2)		106 868		33.71 2.90
Proved Plus Probable Reserves	Light and Medium Crude Oil(1) Natural Gas(2)		123 1,116		30.77 2.76

Notes:

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

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

(3) Calculated using net oil or net gas reserves and forecast price and cost assumptions.

G-7

Estimated Production for Gross Reserves Estimates

The volume of production estimated by Paddock for 2008 in preparing the estimates of gross Proved Reserves and gross Probable Reserves is set forth below.

	Gross Proved Reserves		Gross Probable Reserves
Product Type	Estimated 2008 Aggregate Production	Estimated 2008 Average Daily Production	Estimated 2008 Aggregate Production	Estimated 2008 Average Daily Production
Light and Medium Crude Oil	579 Mbbls	1,581 bbls/d	22 Mbbls	61 bbls/d
Natural Gas Liquids	289 Mbbls	791 bbls/d	4 Mbbls	10 bbls/d
Total Liquids	868 Mbbls	2,372 bbls/d	26 Mbbls	71 bbls/d
Natural Gas	40,200 MMcf	109,836 Mcf/d	1,100 MMcf	3,006 Mcf/d
Total	7,568 MBOE	20,678 BOE/d	209 MBOE	572 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 “Other Oil and Gas Information  - Exploration and Development Activities”):

	Proved Reserves				Proved Plus Probable Reserves
Year	Undiscounted		Discounted at 10%/year		Undiscounted		Discounted at 10%/year
	(in $ millions)
2008		111		107		114		109
2009		99		86		103		89
2010		53		42		85		67
2011		18		13		46		33
2012		-		-		-		-
Remainder		-		-		-		-
Total		281		248		348		298

Other Oil and Gas Information

In this Appendix “G”, minor amounts of heavy oil produced by Focus have been included with light and medium crude oil volumes as the heavy oil volumes are not material.

Principal Properties

The following is a description of the principal Focus’ Properties as of December 31, 2007. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2007. Reserve amounts are stated on a company interest basis, as at December 31, 2007, based on forecast cost and price assumptions as evaluated in the Paddock Focus Report. References below to “Focus” means Focus as it existed prior to its acquisition by Enerplus on February 13, 2008.

All of the producing Focus Properties are located onshore in Canada, specifically in eight main areas in Saskatchewan, Alberta and British Columbia. These are comprised of the natural gas producing areas of Shackleton, Tommy Lakes, Southwest Saskatchewan, Kotcho-Cabin, Pouce Coupe, Sylvan Lake, and Medicine Hat and the oil producing area of Red Earth. Focus has a high working interest in these properties which averages 82 percent, and 93 percent of the production is operated by Focus. Discussion of these areas follows.

G-8

Tommy Lakes, British Columbia

The Tommy Lakes property is located in northeastern British Columbia. The main producing zone at Tommy Lakes is the areally extensive blanket sand of the Triassic Halfway formation. During 2007, Focus’ gross production from the Tommy Lakes property averaged 33 MMcf/d of natural gas and 720 bbls/d of NGLs. Production at the property is compressed at four Focus-operated facilities and delivered into the Duke system for further processing and delivery to markets. At December 31, 2007, Tommy Lakes represented approximately 34 percent of Focus’ reserves. Net capital expenditures on this property in 2007 were approximately $30 million and 11 gross (10.2 net) wells were drilled. Enerplus’ 2008 plans for this property include an increase in drilling activity to approximately 17 gross (16.7 net) wells.

Shackleton, Saskatchewan

The Shackleton area is located in southwestern Saskatchewan. Production at Shackleton is from the Cretaceous Milk River formation, which produces sweet dry natural gas from relatively shallow depths ranging from 1,300 to 1,800 feet. This long life natural gas property is characterized by operated high working interest production, a large inventory of low risk drilling locations, low production expenses, low Crown royalty rates, and a dominant land position.

During 2007, Focus’ gross production from Shackleton averaged 68 MMcf/d of natural gas. Production at Shackleton is compressed and dehydrated at 13 Focus-operated facilities and delivered into the Transgas system for delivery to markets. At December 31, 2007, Shackleton represented approximately 52 percent of Focus’ reserves.

Focus has been very active in developing the Shackleton asset, drilling 370 gross (284.7 net) wells in 2007. Enerplus intends to drill approximately 290 gross (250 net) wells at Shackleton in 2008.

Red Earth, Alberta

Focus’ light oil production is concentrated in the Red Earth area, within which the main producing properties are Golden, Loon Lake, Loon Lake North, Evi, and Kitty. In 2007, Focus’ gross production from the Red Earth area averaged 1,477 bbls/d of light sweet crude oil and 17 bbls/d of NGLs. Approximately 41 percent of the Red Earth production is operated by Focus.

The majority of the assets in these areas, excluding the Golden and Loon Lake properties, are held indirectly through a partnership with Harvest Operations Corp. Focus has a 40 percent interest in the partnership. Focus owns an average 90 percent working interest in the Golden area and an average 41 percent working interest in the Loon Lake area.

Southwest Saskatchewan

Gross production for 2007 in the Southwest Saskatchewan area averaged 2.9 MMcf/d of natural gas and 273 bbls/d of medium and heavy oil. The primary producing horizons are the Milk River, Second White Specks and Glauconitic formations.

Kotcho-Cabin, British Columbia

At Kotcho and Cabin, Focus produces natural gas from several sour high-pressure pools along a dolomitized reef edge in the Devonian Slave Point formation. Production from both properties is processed through 100 percent Focus-owned dehydration and water disposal facilities and delivered to the Duke system. During 2007, Focus’ gross production from this area averaged 1.4 MMcf/d of natural gas.

Pouce Coupe, Alberta

At Pouce Coupe, Focus produces natural gas and associated NGLs from the Triassic Montney and Doig formations. Focus’ gross production from this property in 2007 averaged 2.9 MMcf/d of natural gas and 39 bbls/d of crude oil and NGLs. The majority of production is compressed at a 100 percent Focus-owned facility and then delivered to a third party plant for further processing and delivery onto the TransCanada pipeline system.

G-9

Sylvan Lake, Alberta

Sylvan Lake is a multi-zone area which produces both natural gas and light crude oil from a number of formations ranging in depth from 1,300 to 7,200 feet. The primary producing zones are the Shunda, Pekisko, Lower Mannville, and Edmonton. In 2007, Focus’ gross production from the area averaged 1.7 MMcf/d of natural gas, and 111 bbls/d of oil and NGLs. Production at Sylvan Lake is processed through the Focus-operated Sylvan Lake natural gas plant, in which Focus holds an average working interest of 60 percent. Focus owns excess capacity in this plant which generates significant third party processing income.

Medicine Hat, Alberta

The Medicine Hat property produces sweet natural gas from the Milk River, Medicine Hat and Second White Specks formations. In 2007 Focus’ gross production from the property averaged 2.1 MMcf/d of natural gas. Production is compressed at two Focus operated facilities and delivered to the TransCanada and TransGas pipeline systems.

Summary of Principal Production Locations

During the year ended December 31, 2007, on a BOE basis, 13% of Focus’ production was derived from Alberta, 57% from Saskatchewan and 30% from British Columbia. The following table describes Focus’ principal producing properties and the average daily production from those properties during the year ended December 31, 2007.

2007 Average Daily Production

Property	Light & Medium Crude Oil		NGLs		Natural Gas		Total
	(bbls/d)		(bbls/d)		(Mcf/d)		(BOE/d)
Shackleton, Saskatchewan		-		-		68,051		11,342
Tommy Lakes, British Columbia		-		720		33,000		6,220
Red Earth, Alberta		1,477		17		-		1,494
Southwest Saskatchewan		273		-		2,886		754
Pouce Coupe, Alberta		11		28		2,864		516
Sylvan Lake, Alberta		56		55		1,743		402
Medicine Hat, Alberta		-		-		2,074		345
Kotcho-Cabin, British Columbia		-		-		1,429		238
TOTAL		1,817		820		112,047		21,311

Oil and Natural Gas Wells and Unproved Properties

The following table summarizes, as at December 31, 2007, Focus’ interests in producing wells and in non-producing wells which were not producing but which may be capable of production, along with Focus’ 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.

G-10

	Producing Wells								Non-Producing Wells								Unproved Properties (thousand of acres)
	Oil				Natural Gas				Oil				Natural Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta		189		82		145		106		38		16		12		8		14.5		10.4
Saskatchewan		79		32		1,659		1,382		14		11		181		112		412.9		314.4
British Columbia		-		-		130		121		-		-		17		14		76.8		63.9
Total		268		114		1,934		1,609		52		27		210		134		504.2		388.7

Focus expects its rights to explore, develop and exploit on approximately 56,193 net acres of Unproved Properties to ordinarily expire prior to December 31, 2008. Focus has no material work commitments on such properties and, where Enerplus (as successor to Focus) determines appropriate, it can extend expiring leases by either making the necessary applications to extend or performing the necessary work.

Exploration and Development Activities

During 2007, Focus participated in the drilling of 384 gross oil and natural gas wells (296.2 net wells) with a 100% net well success rate. No service wells were drilled and there were no dry or abandoned wells. Essentially all of the drilling activity was in the Shackleton shallow natural gas area in southwest Saskatchewan and the Tommy Lakes area in northeastern British Columbia. The following table summarizes the number and type of wells that Focus drilled or participated in the drilling of for the year ended December 31, 2007. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

	Development Wells				Exploratory Wells
Category of Well	Gross		Net		Gross		Net
Crude oil wells		3		1.3		-		-
Natural gas wells		381		294.9		-		-
Total		384		296.2		-		-

Enerplus currently intends to focus its development activities with respect to the Focus Properties in the Shackleton shallow natural gas area in southwest Saskatchewan and the Tommy Lakes natural gas area of northeastern British Columbia.

Quarterly Production History

The following table sets forth Focus’ average daily production volumes, on a gross basis, for each fiscal quarter in 2007 and for the entire year.

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Crude oil
Light and medium crude oil (bbls/d)		1,911		1,798		1,750		1,810		1,817
Natural gas liquids (bbls/d)		810		831		913		724		820
Total liquids (bbls/d)		2,721		2,629		2,663		2,534		2,637
Natural gas (Mcf/d)		115,515		115,585		109,728		107,473		112,047
Total (BOE/d)		21,974		21,894		20,951		20,446		21,311

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Quarterly Netback History

The following tables set forth Focus’ average netbacks received for each fiscal quarter in 2007 and for the entire year (excluding the effects of commodity derivative instruments). 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 additional information on production costs, see Note 2 to the table below.

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Light and Medium Crude Oil ($ per bbl)
Sales price(1)		62.17		67.73		76.15		78.85		71.12
Royalties		10.94		12.78		13.02		15.81		13.12
Production costs(2)		13.38		13.64		11.83		16.45		13.84
Netback		37.85		41.31		51.30		46.59		44.16

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Natural Gas Liquids ($ per bbl)
Sales price(1)		55.35		61.35		61.25		77.09		63.36
Royalties		4.86		13.40		13.21		15.76		11.79
Production costs(2)		3.88		2.58		2.81		3.84		3.24
Netback		46.61		45.37		45.23		57.49		48.33

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Natural Gas ($ per Mcf)
Sales price(1)		7.12		6.99		5.58		6.07		6.45
Royalties		1.47		1.44		0.99		1.07		1.25
Production costs(2)		0.61		0.47		0.52		0.68		0.57
Netback		5.04		5.08		4.07		4.32		4.63

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total for Year
Total ($ per BOE)
Sales price(1)		44.87		44.78		38.26		41.62		42.42
Royalties		8.82		9.10		6.87		7.57		8.11
Production costs(2)		4.50		3.71		3.84		5.15		4.29
Netback		31.55		31.97		27.55		28.90		30.02

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, or withholding taxes) and other costs.

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Abandonment and Reclamation Costs

In connection with its operations, Enerplus will incur abandonment and reclamation costs on the Focus Properties for surface leases, wells, facilities and pipelines. Focus has historically budgeted for and recognized as a liability the estimated fair value of the future retirement obligations associated with its property, plant and equipment and estimated such costs through a model that incorporates data from operating history, industry information sources and a cost formula used by Alberta’s Energy Resources and Conservation 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 $63.7 million on an undiscounted basis and $19.6 million discounted at 10%. The calculations of future net revenue under “--  Oil and Natural Gas Reserves of Focus” above have excluded approximately $3.7 million on an undiscounted basis and $9.9 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, Focus has advised Enerplus that it anticipates that a total of approximately $1.1 million on an undiscounted basis and $0.9 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

Costs Incurred

In the financial year ended December 31, 2007, Focus made the following expenditures, all of which were made in Canada:

	Property Acquisition Costs		Development Costs
	($ in thousands)
Costs incurred	$	6,221	$	109,919

Marketing Arrangements and Forward Contracts

Crude Oil and NGLs

Focus received an average price (net of transportation costs but before the effects of commodity derivative instruments) of $71.12/bbl for its light and medium crude oil and $63.36/bbl for its NGLs for the year ended December 31, 2007, compared to $68.31/bbl for its light and medium crude oil and $61.52/bbl for its NGLs for the year ended December 31, 2006.

Natural Gas

Focus’ natural gas production is sold primarily in the provinces of Alberta, Saskatchewan and British Columbia at prevailing spot market prices. The average price received by Focus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2007 was $6.45/Mcf compared to $6.43/Mcf in the year ended December 31, 2006.

Future Commitments and Forward Contracts

The following table sets forth the financial instruments and physical contracts in place at the date of this Annual Information Form on the Focus Properties:

Financial Contracts	Daily Quantity	Contract Price	Price Index	Term
Crude Oil	400 bbls 400 bbls 400 bbls	$78.53 $70.00-$79.00 $84.60	WTI WTI WTI	January 2008 - December 2008 January 2008 - June 2008 July 2008 - December 2008
Natural gas	15,000 GJ 15,000 GJ 10,000 GJ 15,000 GJ 15,000 GJ	$8.25-$9.00 $8.02 $8.60 $6.35 $6.80	AECO AECO AECO AECO AECO	November 2007 - March 2008 November 2007 - March 2008 November 2007 - March 2008 April 2008 - October 2008 April 2008 - October 2008

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Physical Sales Contacts	Daily Quantity	Contract Price	Term
Natural Gas  - fixed price	10,000 GJ 10,000 GJ	$8.96 $7.32	November 2007 - March 2008 November 2007 - March 2008

Information Concerning Focus Limited Partnership

Capitalized terms referred to in this section and not otherwise defined in this Annual Information Form have the same meaning as set forth in the Exchangeable Unit Provisions attached as Schedule “A” to the Focus LP Agreement, a copy of which was filed on the Fund’s profile on the SEDAR website at www.sedar.com as a “Security holders document” on February 19, 2008 and on the EDGAR website at www.sec.gov on Form 6-K on February 20, 2008.

General

Focus LP is a limited partnership formed under the laws of Alberta. The head and principal office of Focus LP is located at The Dome Tower, Suite 3000, 333 - 7th Avenue S.W., Calgary, Alberta T2P 2Z1. The general partner of Focus LP is FET Management Ltd. The Focus LP General Partner is indirectly wholly-owned by the Fund. The Focus LP General Partner is entitled to receive a distribution in each fiscal year equal to 0.001% of the net income of Focus LP. The partners of Focus LP must at all times not be Non-Residents.

The business of Focus LP consists of conducting, and acquiring, investing in, holding, transferring, disposing of and otherwise dealing with securities of whatever nature and kind of, or issued by, the Fund or any associate or affiliate of the Fund or any associate or affiliate thereof, or of, or issued by, any other corporation, partnership, trust or other person involved, directly or indirectly, in any business which involves exploring for or drilling, extracting, gathering, processing, transporting, buying, storing or selling of petroleum, natural gas, natural gas liquids, water, minerals or other related products, power or other forms of energy, and all related businesses and such other businesses as the Board of Directors may determine, and activities ancillary and incidental thereto, whether carried on directly or indirectly or through another person.

Partnership Units

Focus LP is authorized to issue an unlimited number of Focus LP A Units and Focus LP Exchangeable Units. The Focus LP General Partner may, in respect of Focus LP, also issue at any time units of any class or series or secured and unsecured debt obligations, debt obligations convertible into any class or series of units, or options, warrants, rights, appreciation rights or subscription rights relating to any class or series of units, to the Focus LP General Partner, to limited partners or any other person who is not a Non-Resident and is not Tax-Exempt. Each unit ranks equally with each other unit of the same class or series and entitles the holder thereof to the same rights and obligations as the holder of any other unit of the same class or series and no limited partner is entitled to any privilege, priority or preference in relation to any other limited partner holding units of the same class or series.

In addition, on a distribution of assets in the event of the liquidation, dissolution or winding-up of Focus LP, whether voluntary or involuntary, or any other distribution of the assets of Focus LP among its partners for the purpose of winding-up its affairs: (a) the holders of Focus LP A Units will be distributed an amount equal to the Exchange Ratio Percentage of the aggregate of all of the liabilities of the Fund and all other subsidiaries of the Fund that are not direct or indirect wholly-owned subsidiaries of Focus LP; and (b) the balance of the assets of Focus LP will be distributed: (i) as to that proportion of such assets equal to the result obtained by dividing the amount of such assets by the sum of (A) the number of Focus LP Exchangeable Units multiplied by the Exchange Ratio Percentage and (B) the number of Trust Units, in each case as outstanding on the date of such distribution, in respect of each Focus LP Exchangeable Unit outstanding; and (ii) as to the remaining portion of such assets, to the holders of Focus LP A Units rateably in accordance with the number of Focus LP A Units held thereby.

G-14

Focus LP A Units

Focus LP A Units are only permitted to be issued to, and held by, the Fund or an affiliate thereof. Holders of Focus LP A Units are entitled to one vote for each Focus LP A Unit on any Ordinary LP Resolution or Extraordinary LP Resolution of Focus LP. A holder of Focus LP A Units is entitled to receive, and the Focus LP General Partner shall, subject to applicable law, from time to time pay distributions on each Focus LP A Unit as the Focus LP General Partner determines. Such distributions will be paid out of money, assets or property of Focus LP properly applicable to the payment of distributions or out of authorized but unissued Focus LP A Units, as applicable.

Focus LP Exchangeable Units

In 2006, Focus LP issued 10 million Focus LP Exchangeable Units to securityholders of Profico Energy Management Ltd. (“Profico”) who elected to receive and were entitled to receive Focus LP Exchangeable Units instead of, or in addition to, trust units of Focus in consideration for their Profico common shares pursuant to the acquisition by Focus of Profico. As of March 5, 2008, there were 9,086,666 Focus LP Exchangeable Units issued and outstanding, exchangeable into an aggregate of 3,861,833 Trust Units of the Fund. The Focus LP Exchangeable Units may also be issued in respect of other acquisitions made by Focus LP from time to time. The Focus LP General Partner shall ensure, in good faith and in its sole discretion, the economic equivalence of Focus LP Exchangeable Units to Trust Units, after giving effect to the 0.425 exchange ratio.

The principal terms of Focus LP Exchangeable Units are:

(a) Focus LP Exchangeable Units are exchangeable for no additional consideration for 0.425 of a Trust Unit at the option of the holder in accordance with the terms and conditions of the Focus LP Agreement, the Focus LP Support Agreement and the Focus LP Voting and Exchange Agreement. See below under “--  Information Concerning Focus Limited Partnership  - Focus LP Voting and Exchange Agreement  - Exchange Right”;

(b) each Focus LP Exchangeable Unit entitles the holder thereof to receive non-interest bearing loans from Focus LP equal to cash distributions made by the Fund on a Trust Unit, multiplied by 0.425. See below under “--  Information Concerning Focus Limited Partnership  - Partnership Units  - Focus LP Exchangeable Units  - Distribution Rights”;

(c) the holder of each Focus LP Exchangeable Unit will be entitled to direct the Voting and Exchange Trustee to vote the Focus LP Special Voting Right at all meetings of the Fund’s unitholders on the basis of 0.425 of a vote for each Focus LP Exchangeable Unit;

(d) the holders of Focus LP Exchangeable Units will not be entitled as such to receive notice of or to attend any meeting of the partners of Focus LP or to vote at any such meeting. However, holders of Focus LP Exchangeable Units will be entitled to vote separately as a class in respect of proposals to add to, change or remove any right, privilege, restriction or condition attaching to Focus LP Exchangeable Units or in respect of any other amendment to the applicable partnership agreement which will have an adverse impact on the holders of such Focus LP Exchangeable Units. See below under “--  Information Concerning Focus Limited Partnership  - Partnership Units  - Focus LP Exchangeable Units  - Voting Rights”;

(e) Focus LP Exchangeable Units will not be transferable except as set out below under “--  Information Concerning Focus Limited Partnership  - Partnership Units  - Focus LP Exchangeable Units  - Transfer of Focus LP Exchangeable Units”; and

(f) Focus LP will be entitled to acquire all of Focus LP Exchangeable Units in exchange for Trust Units in certain specified circumstances, including there being outstanding fewer than 1,000,000 Focus LP Exchangeable Units or in the event of certain transactions which may involve a change of control of the Fund. See below under “--  Information Concerning Focus Limited Partnership  - Partnership Units  - Focus LP Exchangeable Units  - Redemption Right”.

G-15

The exchange, voting and distribution rights associated with Focus LP Exchangeable Units and the associated Special Voting Right as described below in greater detail are subject to standard anti dilution provisions.

Distribution Rights

Holders of Focus LP Exchangeable Units are entitled to receive, and Focus LP will, subject to applicable law, on each date on which the Fund declares a distribution on Trust Units, declare a loan in respect of each Focus LP Exchangeable Unit:

(a) in the case of a cash distribution declared on Trust Units, in an amount in cash for each Focus LP Exchangeable Unit equal to the cash distribution declared on each Trust Unit, multiplied by 0.425; or

(b) in the case of a distribution declared on Trust Units in property other than cash or Trust Units, in such type and amount of property for each Focus LP Exchangeable Unit as is the same as, or economically equivalent to, the type and amount of property declared as a distribution on each Trust Unit, multiplied by 0.425.

Any amount or value of property loaned in respect of Focus LP Exchangeable Units pursuant to these distribution entitlements will not constitute a distribution of profits or other compensation by way of income in respect of such Focus LP Exchangeable Units but rather will constitute a non-interest bearing loan of the amount thereof, or in the case of property, the fair market value thereof as determined in good faith by the Board of Directors as of the date of such loan, to the holder of Focus LP Exchangeable Units receiving the same, which loan will be repayable by such holder to Focus LP on the earlier of: (a) January 1 of the calendar year next following the loan; (b) the 5th business day preceding any Insolvency Event; (c) the business day prior to the redemption of Focus LP Exchangeable Units in respect of which the loans were made (pursuant to the Retraction Right or any redemption by Focus LP); (d) the business day prior to the purchase of Focus LP Exchangeable Units in respect of which the loan was made pursuant to the Liquidation Call Right; and (e) the business day prior to any other transfer of Focus LP Exchangeable Units in respect of which the loan was made. On the date on which the loan is repayable as determined in the immediately preceding sentence, Focus LP will make a distribution in respect of each Focus LP Exchangeable Unit equal to the amount of the loan outstanding in respect thereof. Focus LP will set off and apply the amount of any such distribution against the obligations of any holder of Focus LP Exchangeable Units under any loan outstanding in respect thereof and each holder of Focus LP Exchangeable Units will have the right to set off and apply any amount owed by such holder of Focus LP Exchangeable Units under any loan outstanding in respect thereof against the amount of any such distribution.

Transfer of Focus LP Exchangeable Units

No holder of Focus LP Exchangeable Units may sell, assign, encumber, grant a security interest in, cause Focus LP to redeem or otherwise dispose of or transfer (or permit any of the foregoing to occur), whether voluntarily or involuntarily or otherwise, its Focus LP Exchangeable Units, except in accordance with operation of law or with respect to a re-registration of certificates evidencing Focus LP Exchangeable Units that does not involve a change in beneficial ownership.

Retraction Right

Pursuant to the Retraction Right, holders of Focus LP Exchangeable Units will be entitled at any time prior to January 8, 2017 to require Focus LP to redeem any or all of Focus LP Exchangeable Units held by such holder for the Retraction Price, which shall be satisfied by Focus LP causing to be delivered to such holder the Focus LP Exchangeable Unit Consideration representing the Retraction Price.

Holders of Focus LP Exchangeable Units may effect such exchange by presenting a certificate or certificates to the Focus LP General Partner or the transfer agent as may be specified by Focus LP representing the number of Focus LP Exchangeable Units the holder desires to have Focus LP redeem together with such other documents as may be required to effect the transfer of Focus LP Exchangeable Units under the Focus LP Agreement and such additional documents and instruments as the transfer agent for Focus LP Exchangeable Units and the Focus LP General Partner may reasonably require to effect the exchange together with a duly completed Retraction Request.

G-16

Focus LP will thereafter cause the Focus LP Exchangeable Unit Consideration to be delivered to the holder of Focus LP Exchangeable Units. For greater clarity, the Focus LP Exchangeable Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit redeemed.

Liquidation Right

Subject to the Liquidation Call Right of the Fund or its applicable subsidiary described below, in the event of the liquidation, dissolution or winding-up of Focus LP, whether voluntary or involuntary, or any other distribution of the assets of Focus LP among its partners for the purpose of winding-up its affairs, a holder of Focus LP Exchangeable Units will be entitled, subject to applicable law, to receive from the assets of Focus LP, in respect of each such Focus LP Exchangeable Unit held on the Liquidation Date, the Liquidation Amount, which shall be satisfied by Focus LP causing to be delivered to such holder the Focus LP Exchangeable Unit Consideration representing the Liquidation Amount. For greater clarity, the Focus LP Exchangeable Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit.

Liquidation Call Right

Upon the occurrence of an event as described above under “--  Liquidation Right”, pursuant to the Liquidation Call Right, the Fund or its applicable subsidiary will have the overriding right to purchase from all but not less than all of the holders (other than the Fund and its affiliates) of Focus LP Exchangeable Units on the Liquidation Date all but not less than all of such holders’ Focus LP Exchangeable Units for the Liquidation Amount and, upon the exercise of this right, the holders thereof will be obligated to sell such Focus LP Exchangeable Units to the Fund or its applicable subsidiary. For the purposes of completing the purchase of Focus LP Exchangeable Units pursuant to the Liquidation Call Right, the Fund or its applicable subsidiary will deposit or cause to be deposited with the transfer agent for such Focus LP Exchangeable Units, on or before the Liquidation Date, the Focus LP Exchangeable Unit Consideration representing the Liquidation Amount. Upon the surrender to the transfer agent by a holder of such Focus LP Exchangeable Units of its certificate(s) representing Focus LP Exchangeable Units, together with such other documents and instruments as may be required to effect a transfer of Focus LP Exchangeable Units pursuant to the Focus LP Agreement, the transfer agent will deliver the Focus LP Exchangeable Unit Consideration to which such holder is entitled. For greater clarity, the Focus LP Exchangeable Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit subject to the Liquidation Call Right.

Redemption Right

Subject to applicable law, Focus LP shall, on the Redemption Date, redeem all but not less than all of the then outstanding Focus LP Exchangeable Units for the Redemption Price. Payment of the total Redemption Price shall be made by delivery of the Focus LP Exchangeable Unit Consideration representing the total Redemption Price to each holder of Focus LP Exchangeable Units. For greater clarity, the Focus LP Exchangeable Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit redeemed.

For the purposes of the Focus LP Exchangeable Unit provisions, “Redemption Date” means the date, if any, established by the Board of Directors for the redemption by Focus LP of all but not less than all of the outstanding Focus LP Exchangeable Units (other than Focus LP Exchangeable Units held by the Fund or its affiliates), pursuant to the Redemption Right, which date shall be no earlier than January 8, 2017, unless:

(a) there are less than 1.0 million Focus LP Exchangeable Units outstanding (other than Focus LP Exchangeable Units held by the Fund or its affiliates), such numbers to be adjusted as determined by the Board of Directors, in good faith and in its sole discretion, to give effect to any subdivision, consolidation or distribution in specie of Focus LP Exchangeable Units, any issue or distribution of rights, options or warrants to acquire Focus LP Exchangeable Units (or securities exchangeable for or convertible into or carrying rights to acquire Focus LP Exchangeable Units), any issue or distribution of other securities or rights or evidences of indebtedness or assets, or any other capital reorganization or other transaction affecting Focus LP Exchangeable Units, in which case the Redemption Date shall be the business day determined by the Board of Directors and the Board of Directors shall give such number of days’ prior written notice to the registered holders of Focus LP Exchangeable Units and the Voting and Exchange Trustee as the Board of Directors may determine to be reasonably practicable in such circumstances;

G-17

(b) a Trust Control Transaction occurs in respect of Focus LP, in which case, provided that the Board of Directors determines, in good faith and in its sole discretion, that it is not reasonably practicable to substantially replicate the terms and conditions of Focus LP Exchangeable Units, in connection with such a Trust Control Transaction and that the redemption of all but not less than all of the outstanding Focus LP Exchangeable Units is necessary to enable the completion of such Trust Control Transaction in accordance with its terms, the redemption date shall be the business day determined by the Board of Directors and the Board of Directors shall give such number of days’ prior written notice to the registered holders of Focus LP Exchangeable Units and to the Voting and Exchange Trustee as the Board of Directors may determine to be reasonably practicable in such circumstances;

(c) a Change of Law occurs, in which case the redemption date shall be the business day determined by the Board of Directors and the Board of Directors shall give such number of days’ prior written notice to the registered holders of Focus LP Exchangeable Units and the Voting and Exchange Trustee as the Board of Directors may determine to be reasonably practicable in such circumstances;

(d) a Class B Unit Voting Event is proposed, in which case, provided that the Board of Directors has determined, in good faith and in its sole discretion, that it is not reasonably practicable to accomplish the business purpose intended by the Focus LP Exchangeable Unit Voting Event, which business purpose must be bona fide and not for the primary purpose of causing the occurrence of a Redemption Date, the redemption date shall be the business day prior to the record date for any meeting or vote of the holders of Focus LP Exchangeable Units, to consider the Focus LP Exchangeable Unit Voting Event and the Board of Directors shall give such number of days’ prior written notice of such redemption to the registered holders of Focus LP Exchangeable Units and the Voting and Exchange Trustee as the Board of Directors may determine to be reasonably practicable in such circumstances; or

(e) an Exempt Class B Unit Voting Event is proposed and the holders of Focus LP Exchangeable Units fail to take the necessary action at a meeting or other vote of holders of Focus LP Exchangeable Units, to approve or disapprove, as applicable, the Exempt Focus LP Exchangeable Unit Voting Event, in which case the redemption date shall be the business day following the day on which the holders of Focus LP Exchangeable Units fail to take such action,

provided, however, that the accidental failure or omission to give any notice of redemption under clauses (a), (b) or (c) above to any of such holders of Focus LP Exchangeable Units shall not affect the validity of any such redemption.

In the case of paragraph (a) above, Focus LP will, at least 30 days before any such Redemption Date, send or cause to be sent to each holder of Focus LP Exchangeable Units a notice in writing of the redemption by Focus LP of Focus LP Exchangeable Units held by such holder.

Automatic Redemption

Holders of Focus LP Exchangeable Units are obligated to notify Focus LP of any event or circumstance which would result in such holder becoming or being deemed to become a Non-Resident, as soon as practicable and, in any event, at least 30 days prior to the anticipated Change of Residency Date. On and as of the fifth business day prior to the Change of Residency Date in respect of a holder of Focus LP Exchangeable Units, all but not less than all of such holder’s Focus LP Exchangeable Units will be and be deemed to be transferred to Focus LP for the Automatic Redemption Price per Focus LP Exchangeable Unit, which shall be satisfied by Focus LP depositing or causing to be deposited with the transfer agent for such Focus LP Exchangeable Units the Focus LP Exchangeable Unit Consideration representing the Automatic Redemption Price. Upon the surrender to the transfer agent by a holder of such Focus LP Exchangeable Units of its certificate(s) representing Focus LP Exchangeable Units, together with such other documents and instruments as may be required to effect a transfer of Focus LP Exchangeable Units pursuant to the Focus LP Agreement, the transfer agent will deliver the Focus LP Exchangeable Unit Consideration to which such holder is entitled.

G-18

For greater clarity, the Class B Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit subject to the Automatic Redemption.

Focus LP Agreement

Voting Rights

The holders of Focus LP Exchangeable Units will not be entitled as such to receive notice of or to attend any meeting of the partners of Focus LP or to vote at any such meeting. Notwithstanding the foregoing, holders of Focus LP Exchangeable Units will be entitled to vote separately as a class in respect of certain amendments to the Focus LP Agreement. See “--  Amendment and Approval” below. On every vote taken at every such meeting each holder of Focus LP Exchangeable Units shall be entitled to one vote in respect of each Focus LP Exchangeable Unit held by such holder.

Pursuant to the Fund’s Trust Indenture, the Special Voting Right has been issued in conjunction with Focus LP Exchangeable Units issued. Each Special Voting Right entitles the holder thereof to receive notice of or to attend any meeting of the Fund’s unitholders and to vote at any such meeting. Pursuant to the Focus LP Voting and Exchange Agreement, each of the holders of Focus LP Exchangeable Units is entitled to instruct the Voting and Exchange Trustee to vote the Special Voting Right in respect of the number of Trust Units into which its Focus LP Exchangeable Units are exchangeable. The Special Voting Right issued to the Voting and Exchange Trustee by the Fund entitles the holders of Focus LP Exchangeable Units to 0.425 of a vote at meetings of the Fund’s unitholders for each Focus LP Exchangeable Unit, but has none of the other rights attached to Trust Units. See “--  Information Concerning Focus Limited Partnership  - Focus LP Voting and Exchange Agreement  - Voting Rights”.

Amendment and Approval

Amendments to the Focus LP Agreement may be proposed by the Focus LP General Partner and, subject to the following limitations, will be deemed to be effective if approved by the Focus LP General Partner:

(a) the amendment provisions themselves may not be amended without the unanimous consent of the holders of the limited partnership units of Focus LP;

(b) no amendment shall be made to the Focus LP Agreement which would have the effect of, among other things: (i) preventing the loans or distributions to the holders of Focus LP Exchangeable Units or adversely affecting the rights of the holders of Focus LP Exchangeable Units under the Focus LP Support Agreement; (ii) changing the provision in the Focus LP Agreement that restricts certain distributions or payments on Focus LP A Units or issuances of securities ranking superior to Focus LP Exchangeable Units; (iii) changing the liability of a limited partner; (iv) allowing any limited partner to exercise control over the business of Focus LP; (v) changing the right of a limited partner to vote on resolutions; or (vi) changing Focus LP from a limited partnership to a general partnership, without such amendment being passed by an Extraordinary LP Resolution;

(c) no amendment shall be made to the Focus LP Agreement which would have the effect of adding, changing or removing any right, privilege, restriction or condition attaching to Focus LP Exchangeable Units, or which would have an adverse impact on the holders of Focus LP Exchangeable Units unless such amendment is approved by a class vote of 662/3% of the holders of Focus LP Exchangeable Units; and

(d) no amendment shall be made which would have the effect of adversely affecting the rights and obligations of the Focus LP General Partner becoming effective before 45 days after the resolution approving such amendment.

Partners must be notified of the full details of any amendments to the Focus LP Agreement within 30 days of the effective date of the amendment.

G-19

Focus LP Voting and Exchange Agreement

Capitalized terms referred to in this section and not otherwise defined in this Annual Information Form have the same meaning as set forth in the Focus LP Voting and Exchange Agreement, a copy of which was filed on the Fund’s profile on the SEDAR website at www.sedar.com as a “Security holders document” on February 19, 2008 and on the EDGAR website at www.sec.gov on Form 6-K on February 20, 2008.

Voting Rights

In accordance with the Focus LP Voting and Exchange Agreement, the Fund has issued the Special Voting Right to the Voting and Exchange Trustee, for the benefit of the holders (other than the Fund and its affiliates) of Focus LP Exchangeable Units. The Special Voting Right carries a number of votes, exercisable at any meeting at which the Fund’s unitholders are entitled to vote, equal to the number of Trust Units into which Focus LP Exchangeable Units are then exchangeable multiplied by the number of votes to which the holder of one Trust Unit is then entitled. With respect to any written consent sought from the Fund’s unitholders, each vote attached to the Special Voting Right will be exercisable in the same manner as set forth above.

Each holder of Focus LP Exchangeable Units on the record date for any meeting at which the Fund’s unitholders are entitled to vote is entitled to instruct the Voting and Exchange Trustee to exercise that number of votes attached to the Special Voting Right which relate to Focus LP Exchangeable Units held by such holder. The Voting and Exchange Trustee will exercise each vote attached to the Special Voting Right only as directed by the relevant holder and, in the absence of instructions from a holder as to voting, will not exercise such votes.

The Voting and Exchange Trustee sends to the holders of Focus LP Exchangeable Units the notice of each meeting at which the Fund’s unitholders are entitled to vote, together with the related meeting materials and a statement as to the manner in which the holder may instruct the Voting and Exchange Trustee to exercise the votes attaching to the Special Voting Right, at the same time as the Fund sends such notice and materials to the Fund’s unitholders. The Voting and Exchange Trustee also sends to the holders of Focus LP Exchangeable Units copies of all information statements, interim and annual financial statements, reports and other materials sent by the Fund to its unitholders at the same time as such materials are sent to the unitholders. To the extent such materials are provided to the Voting and Exchange Trustee by the Fund, the Voting and Exchange Trustee also sends to the holders of Focus LP Exchangeable Units all materials sent by third parties to the Fund’s unitholders, including dissident proxy circulars and tender and exchange offer circulars, as soon as possible after such materials are first sent to unitholders.

All rights of a holder of Focus LP Exchangeable Units to exercise votes attached to the Special Voting Right will cease and be terminated immediately upon: (a) the delivery to the Voting and Exchange Trustee of the certificates representing such Focus LP Exchangeable Units in connection with the exercise by that holder of the Exchange Right (unless the Fund shall not have delivered the Focus LP Exchangeable Unit Consideration in exchange therefor); (b) the occurrence of the automatic exchange of Focus LP Exchangeable Units for Trust Units pursuant to the Automatic Exchange Right; (c) the redemption of Focus LP Exchangeable Units pursuant to Focus LP Exchangeable Units provisions or upon the effective date of the liquidation, dissolution or winding-up of Focus LP pursuant Focus LP Exchangeable Units provisions; (d) the automatic redemption of Focus LP Exchangeable Units pursuant to Focus LP Exchangeable Units provisions; (e) the purchase of Focus LP Exchangeable Units from the holder by Focus LP; or (f) the purchase of Focus LP Exchangeable Units from the holder by the Fund or its applicable subsidiary pursuant to the Liquidation Call Right pursuant to Focus LP Exchangeable Units provisions.

With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of Focus LP Exchangeable Units, making necessary amendments or curing ambiguities or clerical errors (in each case provided that the Focus LP General Partner, on behalf of Focus LP, is of the opinion that such amendments are not prejudicial to the interests of the holders of Focus LP Exchangeable Units), the Focus LP Voting and Exchange Agreement may not be amended without the approval of the holders of Focus LP Exchangeable Units.

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Exchange Right

Pursuant to the Exchange Right granted in the Focus LP Voting and Exchange Agreement, upon the occurrence and during the continuance of an Insolvency Event, the Voting and Exchange Trustee on behalf of the holders of Focus LP Exchangeable Units, has the right to require the Fund to purchase any or all of the applicable Focus LP Exchangeable Units held by such holders and the Automatic Exchange Rights for: (a) an amount per Focus LP Exchangeable Unit equal to the Focus LP Exchangeable Unit Price on the last business day prior to the day of closing of the purchase and sale of such Focus LP Exchangeable Units pursuant to the Exchange Right; and (b) the assumption by the Fund of any Partnership Loan Indebtedness in respect of such Focus LP Exchangeable Unit. The Focus LP Exchangeable Unit Price may be satisfied only by the Fund delivering to the Voting and Exchange Trustee, on behalf of the holders of Focus LP Exchangeable Units, the Focus LP Exchangeable Unit Consideration representing the Focus LP Exchangeable Unit Price. For greater clarity, the Focus LP Exchangeable Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit subject to the Exchange Right.

Exchange Right Subsequent to Retraction

Where a holder of Focus LP Exchangeable Units has elected to exercise its Retraction Right in respect of any or all of its Focus LP Exchangeable Units, and Focus LP notifies such holder that it is unable to redeem all such securities as a result of applicable law, the Retraction Request will be deemed to constitute notice from the holder to the Voting and Exchange Trustee instructing the Voting and Exchange Trustee to exercise the Exchange Right.

Automatic Exchange Right

Pursuant to the Automatic Exchange Right granted in the Focus LP Voting and Exchange Agreement, the Fund must give the Voting and Exchange Trustee written notice of a Liquidation Event in the following manner:

(a) in the event of any determination by the Fund to institute voluntary liquidation, dissolution or winding-up proceedings with respect to the Fund or to effect any other distribution of assets of the Fund among the its unitholders for the purpose of winding-up its affairs, at least 60 days prior to the proposed effective date of such liquidation, dissolution, winding-up or other distribution; and

(b) promptly following the earlier of (i) receipt by the Fund of notice of, and (ii) the Fund otherwise becoming aware of, any threatened or instituted claim, suit, petition or other proceedings with respect to the involuntary liquidation, dissolution or winding-up of the Fund or to effect any other distribution of assets of the Fund among the its unitholders for the purpose of winding-up its affairs, in each case where the Fund has failed to contest in good faith any such proceeding commenced in respect of the Fund within 30 days of becoming aware thereof.

Following receipt of such notice of a Liquidation Event, the Voting and Exchange Trustee will give notice, in the form provided by the Fund, to the holders of Focus LP Exchangeable Units describing the Automatic Exchange Right. Immediately prior to the effective time of the Liquidation Event, and in order to enable the holders of Focus LP Exchangeable Units to participate on a pro rata basis with the holders of Trust Units (after giving effect to the 0.425 exchange ratio) in the distribution of the Fund’s assets in connection with a Liquidation Event, the Fund will exchange Focus LP Exchangeable Units for Trust Units based upon the Focus LP Exchangeable Unit Price applicable at that time, which for greater certainty will be on the basis of 0.425 of a Trust Unit for each Focus LP Exchangeable Unit.

Focus LP Support Agreement

Capitalized terms referred to herein and not otherwise defined in this Annual Information Form have the same meaning as set forth in the Focus LP Support Agreement, a copy of which was filed on the Fund’s profile on the SEDAR website at www.sedar.com as a “Security holders document” on February 19, 2008 and on the EDGAR website at www.sec.gov on Form 6-K on February 20, 2008.

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The Focus LP Support Obligation

Under the Focus LP Support Agreement, so long as any Focus LP Exchangeable Units not owned by the Fund or its affiliates are outstanding, the Fund will, among other things:

(a) take all such actions and do all such things as are reasonably necessary or desirable to enable and permit Focus LP, in accordance with applicable law, to pay and otherwise perform its obligations with respect to the satisfaction of the Liquidation Amount, the Retraction Price, the Redemption Price or the Automatic Redemption Price in respect of each of its issued and outstanding Focus LP Exchangeable Units (other than Focus LP Exchangeable Units owned by Focus or its affiliates) upon its liquidation, dissolution or winding-up or any other distribution of its assets among its partners for the purpose of winding-up its affairs, the delivery of a Retraction Request by a holder of Focus LP Exchangeable Units, or a redemption of Focus LP Exchangeable Units by Focus LP; and

(b) not (and will ensure that each of its affiliates does not) exercise its vote as a partner to initiate the voluntary liquidation, dissolution or winding-up of Focus LP or any other distribution of the assets of Focus LP among its partners for the purpose of winding-up its affairs nor take any action or omit to take any action that is designed to result in the liquidation, dissolution or winding-up of Focus LP or any other distribution of the assets of Focus LP among its partners for the purpose of winding-up its affairs.

The Focus LP Support Agreement also provides that so long as any Focus LP Exchangeable Units not owned by the Fund or its affiliates are outstanding, the Fund will not, without prior approval of Focus LP and the holders of Focus LP Exchangeable Units:

(c) issue or distribute Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units) to the holders of all or substantially all of the then outstanding Trust Units by way of distribution, other than an issue of Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units) to holders of Trust Units who exercise an option to receive distributions in Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units) in lieu of receiving cash distributions, or pursuant to any distribution reinvestment plan; or

(d) issue or distribute rights, options or warrants to the holders of all or substantially all of the then outstanding Trust Units entitling them to subscribe for or to purchase Trust Units (or securities exchangeable for or convertible into or carrying rights to acquire Trust Units); or

(e) issue or distribute to the holders of all or substantially all of the then outstanding Trust Units: (i) securities of the Fund of any class other than Trust Units (other than securities exchangeable for or convertible into or carrying rights to acquire Trust Units); (ii) rights, options or warrants other than those referred to in paragraph (b) above; (iii) evidences of indebtedness of the Fund; or (iv) other assets of the Fund,

unless the economic equivalent on a per Focus LP Exchangeable Unit basis (after giving effect to the 0.425 exchange ratio) of such rights, options, warrants, securities, shares, evidences of indebtedness or other assets is issued or loaned simultaneously to the holders of Focus LP Exchangeable Units.

In addition, the Fund may not without the prior approval of Focus LP and the holders of Focus LP Exchangeable Units: (i) subdivide, redivide or change the then outstanding Trust Units into a greater number of Trust Units: (ii) reduce, combine, consolidate or change the then outstanding Trust Units into a lesser number of Trust Units; or (iii) reclassify or otherwise change Trust Units or effect a merger, reorganization or other transaction affecting Trust Units unless the same or an economically equivalent change (after giving effect to the 0.425 exchange ratio) is made simultaneously to, or in the rights of the holders of, Focus LP Exchangeable Units.

In the event that a tender offer, share exchange offer, issuer bid, take-over bid or similar transaction with respect to Trust Units is proposed by the Fund or is proposed to the Fund or its unitholders and is recommended by the Fund, or the board of directors of EnerMark on its behalf, or is otherwise effected or to be effected with the consent or approval of the Fund, or the board of directors of EnerMark on its behalf, and Focus LP Exchangeable Units are not redeemed by Focus LP, the Fund will use its reasonable best efforts expeditiously and in good faith to take all such actions and do all such things as are necessary or desirable to enable and permit holders of Focus LP Exchangeable Units (other than the Fund or its affiliates) to participate in such transaction to the same extent and on an economically equivalent basis as the Fund’s unitholders (after giving effect to the 0.425 exchange ratio).

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The Focus LP Support Agreement also provides that, as long as any outstanding Focus LP Exchangeable Units are owned by any person other than the Fund or any of its affiliates, the Fund will, unless approval to do otherwise is obtained from Focus LP and from the holders of Focus LP Exchangeable Units pursuant to Focus LP Exchangeable Units provisions, remain the direct or indirect beneficial owner of all issued and outstanding voting interests in the capital of Focus LP and the Focus LP General Partner, provided that the Fund will not be in violation of this obligation if any person or group of persons acquires all or substantially all of the assets of the Fund or Trust Units pursuant to any merger of the Fund pursuant to which the Fund is not the surviving entity. With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of Focus LP Exchangeable Units, making certain necessary amendments or curing ambiguities or clerical errors (in each case provided that the Board of Directors is of the opinion that such amendments are not prejudicial to the interests of the holders of Focus LP Exchangeable Units), the Focus LP Support Agreement may not be amended or modified except by an agreement in writing executed by Focus LP, the Focus LP General Partner, and the Fund and approved by the holders of Focus LP Exchangeable Units pursuant to Focus LP Exchangeable Units provisions.

Under the Focus LP Support Agreement, each of the Fund and, in respect of Focus LP Exchangeable Units, Focus LP have agreed to not, and will cause its affiliates not to, exercise any voting rights attached to Focus LP Exchangeable Units held by it or by its affiliates on any matter considered at meetings of holders of Focus LP Exchangeable Units (including any approval sought from such holders in respect of matters arising under the Focus LP Support Agreement).

Upon notice from Focus LP of any event that requires Focus LP to cause to be delivered Trust Units to any holder of Focus LP Exchangeable Units, the Fund shall forthwith issue and deliver the requisite number of Trust Units to be received by, and issued to or to the order of, the former holder of the surrendered Focus LP Exchangeable Units as Focus LP shall direct. All such Trust Units shall be duly authorized, validly issued and fully paid and non-assessable and shall be free and clear of any lien, claim or encumbrance.

Qualification of Trust Units

The Fund has agreed to make such filings and seek such regulatory consents and approvals as are necessary so that Trust Units issuable upon the exchange of Focus LP Exchangeable Units will be issued in compliance with applicable laws in Canada and may be traded freely on the TSX or such other exchange on which Trust Units may be listed, quoted or posted for trading from time to time.

Actions by the Focus LP General Partner under the Focus LP Support Agreement and the Focus LP Voting and Exchange Agreement.

The Focus LP General Partner, on behalf of Focus LP, will take all such actions and do all such things as are necessary or advisable to perform and comply with all provisions of the Focus LP Support Agreement and the Focus LP Voting and Exchange Agreement applicable to Focus LP.

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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