Enerplus Resources Fund — Annual Report 2009

Mar 12, 2010

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ANNUAL INFORMATION FORM

For the year ended December 31, 2009

March 12, 2010

Table of Contents

GLOSSARY OF TERMS	i
ABBREVIATIONS AND CONVERSIONS	iv
PRESENTATION OF ENERPLUS’ OIL AND GAS
RESERVES, RESOURCES AND
PRODUCTION INFORMATION	v
PRESENTATION OF ENERPLUS’
FINANCIAL INFORMATION	viii
FORWARD-LOOKING STATEMENTS
AND INFORMATION	viii
STRUCTURE OF ENERPLUS RESOURCES FUND	1
Enerplus Resources Fund	1
Operating Subsidiaries	1
Organizational Structure	2
GENERAL DEVELOPMENT OF ENERPLUS
RESOURCES FUND	3
General	3
Developments in the Past Three Years	3
BUSINESS OF ENERPLUS	6
Overview	6
Summary of Principal Production Locations	7
Capital Expenditures and Costs Incurred	8
Exploration and Development Activities	10
Oil and Natural Gas Wells and Unproved Properties	11
Enerplus’ Resource Play Types	12
Quarterly Production History	22
Quarterly Netback History	23
Abandonment and Reclamation Costs	25
Tax Horizon	25
Marketing Arrangements and Forward Contracts	26
OIL AND NATURAL GAS RESERVES	27
Summary of Reserves	27
Forecast Prices and Costs	34
Constant Prices and Costs	34
Undiscounted Future Net Revenue by Reserves
Category	35
Net Present Value of Future Net Revenue by
Reserves Category	35
Estimated Production for Gross Reserves Estimates	36
Future Development Costs	36
Reconciliation of Reserves	37
Undeveloped Reserves	42
Significant Factors or Uncertainties	42
Proved and Probable Reserves Not On Production	42
SUPPLEMENTAL OPERATIONAL INFORMATION	43
Health, Safety and Environment	43
Insurance	44
Personnel	44
INFORMATION RESPECTING ENERPLUS
RESOURCES FUND	45
Description of the Trust Units and the
Trust Indenture	45
Description of the Royalty Agreements and Other
Payments Made to the Fund	51
Management and Corporate Governance	52
Unitholder Rights Plan	52
DEBT OF ENERPLUS	53

Bank Credit Facility	53
Senior Unsecured Notes	54
DISTRIBUTIONS TO UNITHOLDERS	56
Cash Distributions	56
Distribution History	57
Canadian Tax Reporting Matters	57
U.S. Tax Reporting Matters	57
INDUSTRY CONDITIONS	59
Overview	59
Pricing and Marketing – Oil	59
Pricing and Marketing – Natural Gas	60
The North America Free Trade Agreement	60
Royalties and Incentives	60
Land Tenure	61
Environmental Regulation	61
Worker Safety	63
RISK FACTORS	64
Risks Related to Enerplus’ Business and Operations	64
Risks Related to Enerplus’ Structure and the
Ownership of the Trust Units	76
Risks Particular to United States and Other
Non-Resident Unitholders	80
MARKET FOR SECURITIES	82
DIRECTORS AND OFFICERS	83
Directors of EnerMark	83
Officers of EnerMark	84
Trust Unit Ownership	84
Conflicts of Interest	85
Audit & Risk Management Committee Disclosure	85
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	85
INTEREST OF MANAGEMENT AND OTHERS IN
MATERIAL TRANSACTIONS	85
MATERIAL CONTRACTS AND DOCUMENTS
AFFECTING THE RIGHTS OF SECURITYHOLDERS	86
INTERESTS OF EXPERTS	86
REGISTRAR AND TRANSFER AGENT	87
ADDITIONAL INFORMATION	87
APPENDIX A – REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR
OR AUDITOR	A-1
APPENDIX B – REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR
OR AUDITOR	B-1
APPENDIX C – REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR
OR AUDITOR	C-1
APPENDIX D – REPORT OF MANAGEMENT AND
DIRECTORS ON RESERVES DATA AND OTHER
INFORMATION	D-1
APPENDIX E – AUDIT & RISK MANAGEMENT
COMMITTEE DISCLOSURE PURSUANT TO
NATIONAL INSTRUMENT 52-110	E-1
APPENDIX F – SUPPLEMENTAL INFORMATION ABOUT
OIL AND GAS PRODUCING ACTIVITIES	F-1
APPENDIX G – INFORMATION REGARDING ENERPLUS
EXCHANGEABLE LIMITED PARTNERSHIP	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 ’’.

‘‘ 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 10[o] API;

‘‘ CBM ’’ means coalbed methane;

‘‘ Chief ’’ means Chief Oil & Gas LLC, a Texas limited liability company, which is the operator of the Marcellus Properties;

‘‘ 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 ’’;

‘‘ CSA Notice 51-324 ’’ means Canadian Securities Administrators Staff Notice 51-324, Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities , issued by the Canadian securities regulatory authorities;

‘‘ 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;

‘‘ EELP’’ means Enerplus Exchangeable Limited Partnership, a limited partnership established under the laws of Alberta and a subsidiary of the Fund;

‘‘ EELP A Units ’’ means the Class A limited partnership units of EELP, all of which are held, directly or indirectly, by the Fund;

‘‘ EELP Agreement ’’ means the amended and restated limited partnership agreement dated February 13, 2008, as amended December 22, 2008, between EnerMark (as successor by amalgamation to FET Management Ltd.) and Focus Commercial Trust pursuant to which EELP is created, as may be amended, supplemented or restated from time to time;

‘‘ EELP Exchangeable LP Unitholders ’’ means the holders from time to time of EELP Exchangeable LP Units;

‘‘ EELP Exchangeable LP Units ’’ means the Class B limited partnership units of EELP, 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 EELP Exchangeable LP Unit;

‘‘ EELP General Partner ’’ means EnerMark;

‘‘ EELP Support Agreement ’’ means the amended and restated support agreement dated February 13, 2008 among the Fund, EELP and EnerMark (as successor by amalgamation to FET Management Ltd.), as may be amended, supplemented or restated from time to time;

‘‘ EELP Voting and Exchange Agreement ’’ means the amended and restated voting and exchange trust agreement dated May 30, 2008 among the Fund, EELP and Computershare Trust Company of Canada, as may be amended, supplemented or restated from time to time;

‘‘ 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;

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM i

‘‘ 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 oil and gas income trust acquired 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 (together with interests in certain minor non-operated oil sands projects) prepared by GLJ dated January 25, 2010 and effective December 31, 2009;

‘‘ Haas ’’ means Haas Petroleum Engineering Services Inc., independent petroleum consultants;

‘‘ Haas Report ’’ means the independent engineering evaluation of Enerplus’ oil, NGLs and natural gas reserves and resources in the Marcellus Properties prepared by Haas dated January 27, 2010 and effective December 31, 2009, utilizing commodity price forecasts of McDaniel (for internal consistency in Enerplus’ reserves reporting) as of January 1, 2010;

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

‘‘ 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);

‘‘ Marcellus Acquisition ’’ means Enerplus’ initial acquisition of an average 21.5% working interest in the Marcellus Properties on September 1, 2009 pursuant to the Marcellus Purchase Agreement and the Marcellus JDA;

‘‘ Marcellus AMI Agreements ’’ has the meaning assigned thereto under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties’’;

‘‘ Marcellus Carry Amount ’’ has the meaning assigned thereto under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties’’;

‘‘ Marcellus JDA ’’ means the Joint Development Agreement dated September 1, 2009 among Enerplus USA and the Marcellus Vendors;

‘‘ Marcellus Properties ’’ means approximately 540,000 gross acres in the Marcellus shale natural gas area, the majority of which is located in Pennsylvania with certain interests located in Maryland and West Virginia;

‘‘ Marcellus Purchase Agreement ’’ means the purchase and sale agreement dated August 19, 2009 among Enerplus USA, as purchaser, and the Marcellus Vendors, which together with the Marcellus JDA provided for the Marcellus Acquisition;

‘‘ Marcellus Vendors ’’ means, collectively, Chief, Chief Exploration & Development LLC (a Texas limited liability company) and a Texas limited partnership managed by Tug Hill, Inc.;

‘‘ McDaniel ’’ means McDaniel & Associates Consultants Limited, independent petroleum consultants;

‘‘ McDaniel Report ’’ means the independent engineering evaluation of Enerplus’ Canadian conventional oil, NGLs and natural gas interests prepared by McDaniel dated February 12, 2010 and effective December 31, 2009, utilizing commodity price forecasts of McDaniel as of January 1, 2010;

‘‘ 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’ western United States oil, NGLs and natural gas interests prepared by NSAI dated January 27, 2010 and effective December 31, 2009, utilizing commodity price forecasts of McDaniel (for internal consistency in Enerplus’ reserves reporting) as of January 1, 2010;

‘‘ NYSE ’’ means the New York Stock Exchange;

ii EN E RP LU S RE SO URC ES 2009 ANNUAL INFORMATION FORM

‘‘ 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, 2009 being EnerMark, ERC, ECT, Enerplus USA and FET Operating Partnership);

‘‘ 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, collectively, the US$494 million principal amount and $40 million principal amount of senior unsecured notes issued by EnerMark, as described under ‘‘ Debt of Enerplus ’’;

‘‘ SIFT Tax ’’, ‘‘ SIFT Provisions ’’ and ‘‘ SIFT Trust ’’ each has the meaning ascribed thereto under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus’ Strategy Post-2010 ’’;

‘‘ 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 EELP Exchangeable LP Unitholders would be entitled to had the EELP Exchangeable LP Unitholders exchanged all of the EELP 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;

‘‘ 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;

‘‘ Trust Indenture ’’ means the Amended and Restated Trust Indenture dated May 30, 2008 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 Computershare Trust Company of Canada, or its successor as trustee of the Fund;

‘‘ TSX ’’ means the Toronto Stock Exchange; and

‘‘ Voting and Exchange Trustee ’’ means Computershare Trust Company of Canada, or its successor as trustee under the EELP Voting and Exchange Agreement.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM iii

Abbreviations and Conversions

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

AECO the physical storage and trading hub for natural Mcfe/d one thousand cubic feet of natural gas gas on the TransCanada Alberta Transmission equivalent per day System (NOVA) which is the delivery point for the MMbbls one million barrels various benchmark Alberta index prices MMBOE[(1)] one million barrels of oil equivalent API American Petroleum Institute MMbtu one million British Thermal Units bbls barrels, with each barrel representing MMcf one million cubic feet 34.972 imperial gallons or 42 U.S. gallons MMcf/d one million cubic feet per day bbls/d barrels per day MMcfe[(1)] one million cubic feet of natural gas equivalent Bcf billion cubic feet MMcfe/d one million cubic feet of natural gas equivalent Bcf/d billion cubic feet per day per day Bcfe[(1)] one billion cubic feet of natural gas equivalent NGLs natural gas liquids BOE[(1)] barrels of oil equivalent NYMEX the New York Mercantile Exchange BOE/d barrels of oil equivalent per day Tcfe[(1)] one trillion cubic feet of natural gas equivalent Mbbls one thousand barrels WTI West Texas Intermediate crude oil that serves as MBOE[(1)] one thousand barrels of oil equivalent the benchmark crude oil for the NYMEX crude Mcf one thousand cubic feet oil contract delivered in Cushing, Oklahoma Mcf/d one thousand cubic feet per day Mcfe[(1)] one thousand cubic feet of natural gas equivalent

Note:

(1) Enerplus has adopted the standard of 6 Mcf of natural gas: 1 bbl of oil when converting natural gas to BOEs, MBOEs and MMBOEs, and 1 bbl of oil and NGLs: 6 Mcf of natural gas when converting oil and NGLs to Mcfes, MMcfes, Bcfes and Tcfes. For further information, see ‘‘ Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information – Barrels of Oil and Cubic Feet of Gas Equivalent ’’.

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

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

To Convert From	To	Multiply By
Mcf	cubic metres	28.174
cubic metres	cubic feet	35.494
bbls	cubic metres	0.159
cubic metres	bbls	6.293
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.4047
hectares	acres	2.471

iv E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

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 McDaniel attached hereto as Appendix A, the Report on Reserves Data by NSAI attached as Appendix B, the Report on Reserves Data by Haas 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, 2009 and the preparation date for such information is March 12, 2010. 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.

Certain of the following definitions and guidelines are contained in the Glossary to NI 51-101 contained in 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

Presentation of Information

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

Enerplus’ actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this Annual Information Form. The estimated future net revenue from the production of 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.

Notice to U.S. Readers

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 to United States or other foreign disclosure standards. For example, although the SEC now generally permits oil and gas issuers, in their filings with the SEC, to disclose both proved reserves and probable reserves (each as defined in the SEC rules), the SEC definitions of proved reserves and probable reserves may differ from the definitions of ‘‘Proved Reserves’’ and ‘‘Probable Reserves’’ under Canadian securities laws. 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, in accordance with Canadian disclosure requirements, Enerplus has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC now generally requires that reserve estimates be prepared using an unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the company’s fiscal year-end, with the option of also disclosing reserve estimates based upon future or other prices. Enerplus has also provided certain supplemental information in this Annual Information Form (presented as ‘‘constant prices’’: see ‘‘ – Description of Price and Cost Assumptions ’’ below) in accordance with the SEC’s pricing requirements. As a consequence of the foregoing, Enerplus’ 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, including contingent resources, whereas Canadian issuers may disclose oil and gas resources. 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM v

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 the Financial Accounting Standards Board’s Accounting Standards Update (ASU) No. 2010-03 ‘‘ Extractive Activies – Oil and Gas (Topic) 932 ’’, which disclosure complies with the SEC’s guidelines regarding disclosure of oil and gas reserves.

BARRELS OF OIL AND CUBIC FEET OF GAS EQUIVALENT

Enerplus has adopted the standard of 6 Mcf of natural gas: 1 bbl of oil when converting natural gas to BOEs, MBOEs and MMBOEs, and 1 bbl of oil and NGLs: 6 Mcf of natural gas when converting oil and NGLs to Mcfes, MMcfes, Bcfes and Tcfes. BOEs, MBOEs, MMBOEs, Mcfes, MMcfes, Bcfes and Tcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do 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 which have been prepared by Haas pursuant to the Haas Report and which relate to Enerplus’ interest in the Marcellus Properties.

‘‘ 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 hydrocarbons 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 ‘‘ Business of Enerplus – Enerplus’ Resource 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;

• (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 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

vi E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

• (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

In this Annual Information Form, the following terms have the meaning assigned thereto in CSA Notice 51-324 and the COGE Handbook:

‘‘ Reserves ’’ are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a 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 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% probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves; and

• at least a 50% 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.

• ‘‘ 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).

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM vii

‘‘ Constant prices and costs ’’ means, unless expressly noted otherwise, prices and costs used in an estimate that are an unweighted average of the closing prices for the applicable commodity on the first day of each of the twelve months in 2009, held constant throughout the estimated lives of the properties to which the estimate applies.

Presentation of Enerplus’ Financial Information

The financial information included and incorporated by reference in this Annual Information Form has been

prepared in accordance with Canadian GAAP. Canadian GAAP differs in some significant respects from U.S. GAAP and therefore this financial information may not be comparable to the financial information of U.S. companies. The principal differences as they apply to the Fund are summarized in Note 14 to the Fund’s audited consolidated financial statements for the year ended December 31, 2009, 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’’, ‘‘intend’’, ‘‘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 forwardlooking 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, drilling programs, development plans and other future expenditures;

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

• Enerplus’ business strategy including its asset and operational focus and transition from an income model to a hybrid growth and income model;

• future acquisitions and dispositions;

• 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 and Enerplus’ strategy for growth;

• Enerplus’ future operating and financial results;

• future abandonment and reclamation costs;

• the application of the SIFT Tax to the Fund, the potential conversion from a trust to a corporation and the potential timing and tax implications thereof;

• the amount and tax treatment of future distributions and dividends paid by Enerplus;

viii E NE RP LU S RE SO UR C ES 2009 ANNUAL INFORMATION FORM

• Enerplus’ tax pools and the time at which Enerplus may incur certain income or other taxes;

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

• future income tax laws and royalty regimes, including anticipated receipts under the Province of Alberta’s drilling royalty credit program.

The forward-looking information and statements contained in Annual Information Form reflect several material factors and expectations and assumptions made by Enerplus including, without limitation, that: Enerplus will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; Enerplus’ conduct and results of operations will be consistent with its expectations; Enerplus and its industry partners will have the ability to develop Enerplus’ oil, gas and bitumen properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; the estimates of Enerplus’ reserves and resources volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; there will be sufficient availability of services and labour to conduct Enerplus’ operations as planned; and Enerplus’ commodity price and other cost assumptions will generally be accurate. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

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 risks relating to:

• volatility in market prices for oil, bitumen, NGLs and natural gas, including changes in supply or demand for those products;

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

• unanticipated operating results including changes or fluctuations in oil, NGLs, natural gas and bitumen production levels;

• changes in foreign currency exchange rates and interest rates;

• changes in development plans by Enerplus or third party operators;

• the ability of Enerplus to access required capital;

• 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 and reliance on industry partners;

• uncertainties associated with estimating reserves and resources;

• competition for, among other things, capital, acquisitions of reserves and resources, undeveloped lands, access to third party processing capacity and skilled personnel;

• incorrect assessments of the value of acquisitions or the failure to complete dispositions;

• 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, regulatory or other legislation applicable to Enerplus’ operations, and Enerplus’ ability to comply with current and future environmental legislation and regulations and other laws and regulations.

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, 2009, 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM ix

AIF

ENERPLUS RESOURCES FUND

Annual Information Form For the year ended December 31, 2009

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 Computershare Trust Company of Canada located at Suite 600, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8. The board of directors of EnerMark is responsible for the governance of Enerplus.

OPERATING SUBSIDIARIES

The Fund’s Operating Subsidiaries acquire, exploit and operate crude oil and natural gas assets for the benefit of the Fund. See ‘‘ Business of Enerplus ’’, ‘‘ 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, 2009, the Fund’s material Operating Subsidiaries were EnerMark, ERC, ECT, Enerplus USA and FET Operating Partnership.

Each of EnerMark and ERC are corporations organized under the Business Corporations Act (Alberta). ECT is a trust organized under the laws of Alberta, FET Operating Partnership is a general partnership 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, Enerplus USA and FET Operating Partnership are indirectly owned by the Fund.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 1

AIF

ORGANIZATIONAL STRUCTURE

The simplified organizational structure of Enerplus as of December 31, 2009, 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.

==> picture [422 x 349] intentionally omitted <==

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UNITHOLDERS
100% Cash
trust distributions
units
EELP EXCHANGEABLE
LP UNITHOLDERS
ENERPLUS
RESOURCES FUND
(Alberta trust)
Cash
distributions
Distribution
100% payments
common Royalty, interest, (indirect)
Distribution shares debt principal and
payments (indirect) dividend payments
EELP (indirect) (direct and indirect)
(Alberta limited 100%
partnership) trust units ENERPLUS
Royalty ENERMARK INC. (indirect) COMMERCIAL
payments (Alberta corporation) TRUST
(Alberta trust)
100% Distribution
interest payments 100% 100% common
(indirect) (indirect) common
Interest and shares (indirect)
shares
dividend payments
(indirect)
FET OPERATING
ENERPLUS RESOURCES ENERPLUS RESOURCES
PARTNERSHIP
(Alberta partnership) CORPORATION (USA) CORPORATION
(Alberta corporation) (Delaware corporation)
25FEB201020010500
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2 EN E RP LU S RE SO URC ES 2009 ANNUAL INFORMATION FORM

General Development of Enerplus Resources Fund

GENERAL

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’’.

DEVELOPMENTS IN THE PAST THREE YEARS

Changes to Taxation of Income Trusts and Enerplus’ Strategy Post-2010

On October 31, 2006, the Canadian Federal Minister of Finance proposed to subject certain types of income of publicly traded mutual fund trusts (a ‘‘ SIFT Trust ’’) to tax at rates comparable to the combined federal and provincial corporate tax rates (the ‘‘ SIFT Tax ’’). 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. However, 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. Any ‘‘undue expansion’’ during this transitional period may cause the SIFT Tax to apply to the Fund before January 1, 2011. For a SIFT Trust, ‘‘normal growth’’ includes equity growth within certain ‘‘safe harbour’’ limits, measured by reference to the market capitalization of the SIFT Trust as of the end of trading on October 31, 2006. 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.

The combined market capitalization of the Fund and Focus 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. After deducting the value of new equity issued after October 31, 2006 and adding the value of new equity which could be issued to replace debt that was outstanding on October 31, 2006, Enerplus’ aggregate remaining ‘‘safe harbour’’ growth limit is approximately $9.0 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 10 to the Fund’s audited consolidated financial statements for the year ended December 31, 2009. 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 anticipates converting to a dividend paying corporation on or about January 1, 2011. Enerplus intends to take advantage of the SIFT Trust conversion rules to significantly simplify its underlying organization structure at the same time Enerplus converts to a corporation. Enerplus currently anticipates that its corporate conversion will be achieved through a plan of arrangement effected under the Business Corporations Act (Alberta) which must be approved by the board of directors of EnerMark as well as the Fund’s unitholders. The Fund intends to seek the required unitholder approval at a special meeting of unitholders to be held in December 2010. There is a risk that the Fund’s unitholders may not approve the conversion to a corporation, however the Canadian government has legislated the SIFT Tax beginning in 2011 which effectively removes the benefits of remaining a trust.

Enerplus does not expect the conversion to a corporation to have a major impact on its underlying operating strategy or business affairs. Furthermore, although there is also a risk that conversion could create a taxable event for some of the Fund’s unitholders, Enerplus currently does not anticipate that the conversion will create a taxable event for its unitholders. However, the final form, structure and steps involved in the conversion transaction have not yet been finalized and as a result Enerplus cannot guarantee that the conversion will not result in a taxable event for its securityholders. Enerplus currently does not expect to adjust its monthly cash dividends as a result of a conversion to a corporation. Going forward, the tax treatment of Enerplus’ dividends or distributions may be different for its securityholders depending on their tax jurisdiction and whether they are holding their investment in a taxable account or tax-deferred account.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 3

For additional information (including with respect to Enerplus’ anticipated tax horizon), see ‘‘ Business of Enerplus – 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 Corporationoperated 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 is not required to expend any development capital or operating costs on these assets.

Acquisition of Kirby Oil Sands Partnership

On April 10, 2007, Enerplus acquired an undivided 90% interest in Kirby Oil Sands Partnership (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 Oil Sands Partnership 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 ‘‘ Business of Enerplus – Enerplus’ Resource Play Types – Oil Sands – Kirby Project ’’.

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. Additionally, the Fund assumed the exchangeable limited partnership units of Focus Limited Partnership (a subsidiary of Focus, since renamed EELP), which became exchangeable into Trust Units of the Fund. The Fund issued an aggregate of 30,149,752 Trust Units to former Focus unitholders in the transaction, and as of December 31, 2009 Enerplus also had outstanding an aggregate of approximately 6,382,000 Exchangeable LP Units, exchangeable into approximately 2,712,000 Trust Units. Each EELP Exchangeable LP Unit is exchangeable for an Enerplus Trust Units on the basis of 0.425 of an Enerplus Trust Unit for each EELP Exchangeable LP Unit, and each EELP Exchangeable LP Unit has voting rights and entitlements to cash distributions in accordance with such exchange ratio. For a description of the EELP Exchangeable LP Units and the agreements relating thereto, see ‘‘ Appendix G – Information Regarding Enerplus Exchangeable Limited Partnership ’’ in this Annual Information Form.

Disposition of Joslyn Project

On July 31, 2008, Enerplus completed the sale of its 15% working interest in the Joslyn oil sands lease to Occidental Petroleum Corporation for net proceeds of approximately $502 million, after adjustments and transaction costs. The proceeds of the sale were used to reduce bank debt. The Joslyn project, located in northeastern Alberta, is an oil sands project operated by Total E&P Canada Ltd., a wholly-owned subsidiary of Total S.A. Enerplus had invested approximately $115 million on its 15% interest in the Joslyn project since its inception in 2002.

Acquisition of Interests in the Marcellus Properties

On September 1, 2009, Enerplus (through the Fund’s indirect wholly-owned subsidiary, Enerplus USA) acquired an average 21.5% working interest in certain lands within the Marcellus shale natural gas play in the northeastern United States. Total consideration for the Marcellus Acquisition was approximately US$411.0 million (approximately Cdn$453.3 million). The transaction had an effective date of May 1, 2009. Under the terms of the transaction, Enerplus acquired an average 21.5% working interest through the acquisition of an undivided 30% interest in the Marcellus Vendors’ average 72% working interest in the Marcellus Properties. The Marcellus Acquisition was completed in two

4 EN E RP LU S RE SO URC ES 2009 ANNUAL INFORMATION FORM

components, with one portion of the interests conveyed to Enerplus pursuant to the Marcellus Purchase Agreement and the remaining portion conveyed to Enerplus pursuant to the Marcellus JDA, as described in further detail below.

Pursuant to the Marcellus Purchase Agreement, Enerplus acquired an approximate 8.6% working interest in the Marcellus Properties (representing an undivided 12% interest in the Marcellus Vendors’ average 72% working interest in the Marcellus Properties) for cash consideration of US$164.4 million (approximately Cdn$181.3 million), which was paid at closing. Enerplus and the Marcellus Vendors also entered into the Marcellus JDA on the closing date of the Marcellus Acquisition, under which Enerplus acquired an additional approximate 12.9% working interest in the Marcellus Properties (representing an undivided 18% interest in the Marcellus Vendors’ average 72% working interest in the Marcellus Properties). Under the terms of the Marcellus JDA, the consideration of US$246.6 million (approximately Cdn$272.0 million) (the ‘‘ Marcellus Carry Amount ’’) for these additional working interests is to be paid over time as a ‘‘carry’’ and will represent 50% of the Marcellus Vendors’ share of the future well drilling and completion costs on the Marcellus Properties until the Marcellus Carry Amount has been fully expended. As of December 31, 2009, the Marcellus Carry Amount was approximately US$237.3 million, after considering 2009 spending as well as final closing adjustments. Based on existing future drilling and completion plans, Enerplus anticipates the Marcellus Carry Amount will be spent by 2013. Since closing of the Marcellus Acquisition, Enerplus has spent approximately $5 million on the purchase of additional acreage and seismic data in the Marcellus play.

For a description of the Marcellus Properties and Enerplus’ shale gas resource play, see ‘‘ Business of Enerplus – Enerplus’ Resource Play Types – Marcellus Shale Gas ’’.

Additional Strategic Acquisitions and Dispositions

In 2009, Enerplus acquired additional Bakken land interests in southeast Saskatchewan and North Dakota for a purchase price of approximately $55.0 million, and disposed of $104.3 million of assets, almost all of which related to the sale of a non-core oil property in western Canada, with production of approximately 200 BOE/d.

In early 2010, Enerplus announced that it intends to dispose of approximately 14,000 BOE/d of non-core production that does not fit with Enerplus’ strategy going forward. Enerplus intends to use the proceeds of such dispositions, if any, on strategic acquisitions and capital spending.

Strategic Positioning in the Current Economic and Industry Environment

2009 was a transition year for Enerplus as it continued to move from an income model to a growth and income-oriented model. Early in 2009, in response to the steep decline in commodity prices and the global credit crisis, Enerplus lowered its monthly cash distributions to $0.18 per Trust Unit and significantly reduced its development capital program. This was done to ensure it maintained a strong balance sheet to provide the financial flexibility and liquidity to pursue growth assets. Throughout 2010 Enerplus expects to continue to transition toward a dividend paying corporation that Enerplus believes will offer investors both growth and income. For additional information on Enerplus’ business strategy, see ‘‘ Business of Enerplus – Overview ’’.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 5

Business of Enerplus

OVERVIEW

As described above, 2009 was a transition year for Enerplus as it continued to move from an income model to a growth and income-oriented model. During this transition, Enerplus has been focused on delivering operational results, repositioning its asset base and adding key leadership and technical skills while balancing distributions and capital reinvestment with cash flows. Enerplus believes that it has made significant progress with respect to these strategies and that it is well positioned for success as the new growth plays begin to contribute to its results during 2010.

Enerplus is realigning its asset base to include not only mature income-oriented assets but also early stage, growth-oriented assets such as the Marcellus shale gas play in the U.S., Bakken/tight oil in both Canada and the U.S. and Deep Basin tight gas in Canada. Enerplus believes that it has started to accumulate a meaningful portfolio of growth prospects and expects to continue adding these types of properties to its portfolio. Enerplus also believes a greater concentration of assets will allow it to focus its activities on a fewer number of high impact properties to create the greatest value for its investors.

A key element of Enerplus’ business strategy in 2009 was to add more early-stage resource plays to its portfolio both through acquisitions and organic development. Enerplus believes the addition of these types of plays will help to improve the profitability of its business and position it to show meaningful growth in both reserves and production. Enerplus acquired approximately 226,000 net acres of prospective land, the majority of which was in three key growth areas. The allocation of a portion of the capital budget to early stage resource plays rather than to producing properties negatively impacted year-over-year production growth. In 2009, Enerplus also added to its internal technical skill sets to improve its understanding and exploit its existing crude oil waterflood assets and other oil properties through the use of horizontal drilling, multi-stage fracture stimulation and enhanced oil recovery techniques. These mature properties have been on production for many years but Enerplus believes that they still have a significant amount of recoverable oil. By applying new techniques and technologies Enerplus believes it can improve the ultimate recovery from many of these fields, adding incremental reserves and production. In 2009, Enerplus managed its development capital spending and distributions within cash flow while meeting its production targets and advancing its growth strategy. Enerplus deferred its oil sands program in 2009 to focus its capital in its other growth plays.

Enerplus’ acquisition and development activities are generally focused on ‘‘resource plays’’, which are typically large and aerially extensive accumulations of discovered oil, natural gas and bitumen with limited geological risk. Resource plays typically require many wells to develop the play over time. Resource plays generally exhibit lower production decline rates over the long term and a longer reserve life. Enerplus’ six resource play types include: (i) Bakken/Tight Oil in Montana, North Dakota and southeast Saskatchewan; (ii) Marcellus Shale Gas in the northeastern United States; (iii) Tight Gas in northwestern Alberta and northeastern British Columbia; (iv) Crude Oil Waterfloods throughout western Canada; (v) Shallow Gas (which includes some shallow CBM properties) in southeast and central Alberta and southwest Saskatchewan; and (vi) Oil Sands in northeast Alberta. Additionally, Enerplus has interests in other conventional oil and natural gas properties throughout western Canada. Each of these play types and property interests is described in detail under ‘‘ – Enerplus’ Resource Play Types ’’ below.

Unless otherwise noted, (i) all production and operational information in this Annual Information Form is presented as at or, where applicable, for the year ended, December 31, 2009, (ii) 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, and (iii) all references to reserve volumes represent Enerplus’ estimated company interest reserves (before deduction of royalties) contained in the McDaniel Report, NSAI Report or Haas Report, as applicable, using forecast prices and costs. See ‘‘ Presentation of Enerplus’ Oil and Gas Reserves, Resources and Production Information ’’.

Enerplus’ oil and natural gas property interests are located in western Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, with minor landholdings in Ontario, and in the United States in the states of Montana, North Dakota, Pennsylvania, West Virginia, Maryland, Wyoming and Utah. Enerplus’ major producing properties have related field production facilities and infrastructure to accommodate Enerplus’ production. Production volumes for the year ended December 31, 2009 from Enerplus’ properties consisted of approximately 41% crude oil and NGLs and 59% natural gas, on a BOE basis. Enerplus’ 2009 average daily production was comprised of

6 EN E RP LU S RE SO URC ES 2009 ANNUAL INFORMATION FORM

32,984 bbls/d of crude oil, 4,157 bbls/d of NGLs and 326.6 MMcf/d of natural gas for a total of 91,569 BOE/d, a decrease of approximately 4% on a BOE basis when compared to 2008 average daily production of 34,581 bbls/d of crude oil, 4,627 bbls/d of NGLs and 338.9 MMcf/d of natural gas, for a total of 95,687 BOE/d. Enerplus exited 2009 with average daily production of approximately 85,400 BOE/d. Approximately 71% of Enerplus’ 2009 production was operated by Enerplus and the remaining 29% was operated by industry partners. As at December 31, 2009, the oil and natural gas property interests held by Enerplus were estimated to contain Proved plus Probable Reserves of 110,568 Mbbls of light and medium crude oil, 46,778 Mbbls of heavy crude oil, 14,507 Mbbls of NGLs, 1,013,180 MMcf of natural gas and 24,890 MMcf of shale gas, for a total of 344,864 MBOE. See ‘‘ Oil and Natural Gas Reserves ’’.

The following table outlines Enerplus’ reserves as at December 31, 2009 and its average daily production in 2009, in each case on a company interest basis, for five of Enerplus’ six resource plays and its other conventional oil and natural gas properties. Enerplus’ Oil Sands resource play did not have any production in 2009 and was not assigned any reserves at December 31, 2009.

			Proved Plus
	Proved	Probable	Probable	Average Daily
Play Type	Reserves	Reserves	Reserves	Production
Bakken/Tight Oil	32.0 MMBOE	9.7 MMBOE	41.8 MMBOE	10,075 BOE/d
Crude Oil Waterfloods	74.4 MMBOE	21.4 MMBOE	95.9 MMBOE	16,329 BOE/d
Other Conventional Oil	31.5 MMBOE	10.6 MMBOE	42.2 MMBOE	10,777 BOE/d
Total Oil	138.0 MMBOE	41.8 MMBOE	179.8 MMBOE	37,181 BOE/d
Marcellus Shale Gas	8.1 Bcfe	16.8 Bcfe	24.9 Bcfe	514 Mcfe/d
Tight Gas	252.8 Bcfe	102.8 Bcfe	355.6 Bcfe	98,452 Mcfe/d
Shallow Gas	272.7 Bcfe	95.1 Bcfe	367.8 Bcfe	140,008 Mcfe/d
Other Conventional Gas	182.5 Bcfe	59.3 Bcfe	241.9 Bcfe	87,352 Mcfe/d
Total Gas	716.2 Bcfe	274.0 Bcfe	990.2 Bcfe	326,326 Mcfe/d
Total	257.4 MMBOE	87.5 MMBOE	344.9 MMBOE	91,569 BOE/d

SUMMARY OF PRINCIPAL PRODUCTION LOCATIONS

During the year ended December 31, 2009, on a BOE basis, approximately 61% of Enerplus’ production was derived from Alberta, 17% from Saskatchewan, 11% from Montana, 9% from British Columbia, 2% from Manitoba and minimal amounts from other jurisdictions (such as Pennsylvania, Utah, Wyoming and North Dakota). 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, 2009. All properties listed in the table (other than ‘‘Other’’) are located in Alberta unless otherwise noted.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 7

2009 Average Daily Production from Principal Properties

Property Primary Play Type Shackleton, Saskatchewan Shallow Gas Sleeping Giant, Montana, U.S.A. Bakken/Tight Oil Tommy Lakes, British Columbia Tight Gas Brooks Other Conventional Oil Bantry Shallow Gas Pembina 5 Way Crude Oil Waterflood Giltedge Crude Oil Waterflood Joarcam Crude Oil Waterflood Medicine Hat Glauconitic ‘‘C’’ Unit Crude Oil Waterflood Verger Shallow Gas Elmworth Tight Gas Pine Creek Tight Gas Hanna Garden Shallow Gas Burnt Timber Tight Gas Medicine Hat South Shallow Gas Chinchaga Other Conventional Gas Hanlan-Robb Other Conventional Gas Pouce Coupe Tight Gas Virden, Manitoba Crude Oil Waterflood Ansell Tight Gas Mitsue Crude Oil Waterflood Joffre Shallow Gas Other N/A TOTAL N/A	Product
	Crude Oil Light and Natural Heavy Medium NGLs Gas Total
	(bbls/d) (bbls/d) (bbls/d) (Mcf/d) (BOE/d) – – – 62,736 10,456 – 8,046 – 9,963 9,707 – 83 651 32,799 6,201 2,585 – 66 11,053 4,493 – 10 – 16,172 2,705 – 2,015 126 2,411 2,543 2,077 – – 189 2,109 – 1,333 62 4,181 2,092 1,954 – – 333 2,010 – – – 11,900 1,983 – – 350 8,149 1,708 – 14 345 7,235 1,565 – – 4 9,081 1,518 – – 8 7,946 1,332 – – – 7,636 1,273 – – 16 7,502 1,266 – – 13 7,494 1,262 – 277 41 5,324 1,205 – 1,196 – – 1,196 – – 70 5,893 1,052 – 736 132 1,040 1,041 – – – 5,714 952 2,627 10,031 2,273 101,819 31,900
	9,243 23,741 4,157 326,570 91,569

CAPITAL EXPENDITURES AND COSTS INCURRED

In 2009, Enerplus invested approximately $299 million through its capital program, net of $22 million in drilling royalty credits provided by the Province of Alberta, approximately 48% less than its capital program in 2008. Over 60% of Enerplus’ capital spending in 2009 was invested in mature properties in its Crude Oil Waterflood, Shallow Gas, Tight Gas and Bakken/Tight Oil resource plays. Enerplus’ investment in early stage growth projects grew 49% in 2009 to approximately $82 million, up from $55 million in 2008, and included approximately $30 million in undeveloped land and $30 million in drilling seven net assessment wells in various plays.

8 EN E RP LU S RE SO URC ES 2009 ANNUAL INFORMATION FORM

The following table outlines the capital expenditures made by Enerplus in 2009 with respect to each of its six resource plays and its other conventional oil and natural gas properties, net of $22 million in drilling royalty credits provided by the Province of Alberta.

	2009 Capital
Play Type	Spending
	($ millions)
Bakken/Tight Oil	49
Crude Oil Waterfloods	37
Other Conventional Oil	16
Oil Sands	15
Total Oil	117
Shallow Gas	61
Tight Gas	95
Marcellus Shale Gas	12
Other Conventional Gas	14
Total Gas	182
Total	299

In the financial year ended December 31, 2009, Enerplus made the following expenditures in the categories noted, as prescribed by NI 51-101:

	Property Acquisition Costs Exploration Development Proved Unproved Costs Costs ($ in millions) 2.6 59.7 29.5 194.5 – 487.1(1) 5.0 41.0 2.6 546.8 34.5 235.5	Exploration Development Costs Costs
Canada United States
Total		34.5 235.5

Note:

(1) Includes actual expenditures of $238.8 million and remaining Marcellus Carry Amount obligations at December 31, 2009 of $248.3 million.

Enerplus expects its 2010 capital development spending to be approximately $425 million (net of $33 million in estimated Alberta drilling royalty credits) compared to its 2009 capital expenditures of approximately $299 million. Enerplus anticipates a 42% increase in development capital spending in 2010 versus 2009 given the improvement in crude oil prices and economic conditions, the strength of its balance sheet and increased opportunities associated with early stage growth-oriented assets. This increase in capital spending is primarily related to new opportunities in the Bakken/Tight Oil and the Marcellus Shale Gas resource plays. Enerplus anticipates that approximately $260 million of its 2010 capital budget will be spent on its Canadian assets and $165 million on its U.S. operations, with approximately 55% of its total spending directed at oil opportunities and the remainder on natural gas. Enerplus plans to direct its oil activities primarily at its Bakken properties in Canada and the U.S., as well as crude oil waterflood and conventional oil projects in western Canada. Enerplus’ 2010 natural gas spending plans are primarily concentrated in the Marcellus Shale Gas play, drilling in the Canadian Deep Basin and shallow gas drilling in Alberta that is supported by government incentives. Enerplus’ 2010 capital spending plans include approximately $125 million on drilling, seismic and minor land purchases associated with existing growth properties. The foregoing plans do not include any acquisition activity or large undeveloped land purchases as these are opportunistic and difficult to predict. Enerplus will review its 2010 capital investment plans regularly throughout the year in the context of prevailing economic conditions and potential acquisitions, and make adjustments as it deems necessary. Enerplus anticipates that its 2010 spending will be evenly distributed throughout the year given the nature and location of the spending.

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Enerplus’ currently planned 2010 capital expenditures for each of its resource plays and its other conventional oil and natural gas assets (net of an anticipated $33 million recovered through the Alberta drilling royalty incentive program) is as follows:

	2010 Planned
Play Type	Capital Spending
	($ millions)
Bakken/Tight Oil	117
Crude Oil Waterfloods	96
Other Conventional Oil	18
Oil Sands	–
Total Oil	231
Marcellus Shale Gas	80
Tight Gas	56
Shallow Gas	41
Other Conventional Gas	17
Total Gas	194
Total	425

EXPLORATION AND DEVELOPMENT ACTIVITIES

During 2009, Enerplus participated in the drilling of 429 gross oil and natural gas wells (313.0 net wells), including 138 net wells utilizing the Alberta drilling royalty credit program, with over a 99% net well success rate, along with 5 gross (0.7 net) service wells. The majority of Enerplus’ drilling activity was in the shallow natural gas areas at Shackleton in Saskatchewan and Bantry, Verger and Hanna Garden in Alberta. Almost all of this shallow natural gas activity was in operated areas. Enerplus also had active operated drilling and facility programs in oil dominated areas such as Pembina and Giltedge in Alberta, Freda Lake in Saskatchewan, Virden in Manitoba, and Sleeping Giant in Montana. Non-operated drilling activity in 2009 was focused in deep tight gas areas at Brazeau, Ansell and Elmworth in Alberta, Bakken and tight oil areas at Taylorton in Saskatchewan and in North Dakota, and on Enerplus’ U.S. Marcellus shale gas properties. 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, 2009, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

Category of Well	Canada Development Wells Exploratory Wells Gross Net Gross Net 54 20.5 4 1.8 335 272.7 16 10.9 5 0.7 – – 1 0.1 – – 395 294.0 20 12.7	United	States Exploratory Wells Gross Net
	Development Wells Gross Net	Development Wells Gross Net
Crude oil wells Natural gas wells Service wells Dry and abandoned wells	54 20.5 335 272.7 5 0.7 1 0.1	6 2.9 12 3.1 – – – –	– – 1 1.0 – – – –
Total	395 294.0	18 6.0	1 1.0

For a description of Enerplus planned 2010 development plans and the anticipated sources of funding those plans, see ‘‘– Capital Expenditures and Costs Incurred ’’ above and ‘‘– Enerplus’ Resource Play Types ’’ below.

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OIL AND NATURAL GAS WELLS AND UNPROVED PROPERTIES

The following table summarizes, as at December 31, 2009, 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 Oil Natural Gas Gross Net Gross Net 3,383 1,358.9 7,171 3,561.4 2,478 474.0 2,557 2,318.6 213 27.4 315 178.1 572 318.6 – – – – – – 231 133.7 – – 2 2.0 – – – – 11 2.1 – – – – – – – – 1 1.0 – – – – – – 6,880 2,315.6 10,054 6,060.2	Non-Producing Wells Oil Natural Gas Gross Net Gross Net 1,049 457.1 786 325.9 454 74.7 171 151.0 49 8.1 90 33.1 39 24.6 – – – – – – 1 0.5 – – 2 0.6 – – – – 27 5.3 – – – – – – – – – – – – – – 1 1.0 1,594 565.6 1,075 516.3	Unproved Properties (thousands of acres)
	Oil Gross Net	Oil Gross Net	Gross Net
Alberta Saskatchewan British Columbia Manitoba Ontario Montana North Dakota Pennsylvania Maryland West Virginia Utah Colorado	3,383 1,358.9 2,478 474.0 213 27.4 572 318.6 – – 231 133.7 2 2.0 – – – – – – 1 1.0 – –	1,049 457.1 454 74.7 49 8.1 39 24.6 – – 1 0.5 2 0.6 – – – – – – – – – –	923 378 480 386 287 123 17 12 34 – 13 8 33 21 449 109 21 6 35 10 8 7 42 42
Total	6,880 2,315.6	1,594 565.6	2,342 1,102

Enerplus expects its rights to explore, develop and exploit on approximately 245,358 net acres of unproved properties to expire prior to December 31, 2010 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.

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ENERPLUS’ RESOURCE PLAY TYPES

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

Bakken/Tight Oil

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Enerplus’ Bakken/Tight Oil resource play includes properties in Montana, North Dakota and southeast Saskatchewan, including an approximate 70% average working interest in certain producing wells in the Sleeping Giant Bakken oil field in Richland County, Montana, which is one of Enerplus’ largest producing properties. Existing production from this resource play is primarily from the Middle Bakken dolomite formation at a depth of approximately 10,000 feet and consists of light sweet crude oil (42[o] API) and some associated natural gas. Enerplus’ Bakken/Tight Oil resource play represented approximately 11% of its 2009 average daily production on a BOE basis, with virtually all of this production coming from the Sleeping Giant project, and represented approximately 12% of Enerplus’ Proved plus Probable Reserves as at December 31, 2009. These properties are predominantly operated by Enerplus.

In 2009, Enerplus added to its Bakken/Tight Oil portfolio and has now accumulated approximately 100 net sections of undeveloped Bakken land in both Canada and the U.S. In May 2009, Enerplus purchased a 25% working interest in 44 gross sections of prospective Bakken land in southeast Saskatchewan for $25 million, and followed with the purchase of a 50% working interest in approximately 34 gross sections of prospective Bakken land in North Dakota for US$27 million in October 2009.

In 2009, Enerplus’ Bakken/Tight Oil capital spending was associated with ongoing development of its Sleeping Giant property in Montana and assessment drilling in its new areas. In late 2008, Enerplus suspended its drilling program at Sleeping Giant due to the significant drop in crude oil prices experienced at that time, but continued with its refrac program given the attractive economic returns (a ‘‘refrac’’ consists of the restimulation of a producing formation within an existing wellbore to enhance production and add new incremental reserves). As oil prices stabilized in the latter half of 2009, Enerplus resumed its drilling program and drilled an additional two wells by year-end along with a total of 19 refracs, for total spending of approximately $25 million. Enerplus also spent another $14 million primarily in assessment work in its new areas.

For 2010, Enerplus has currently allocated approximately $117 million in development capital to its Bakken/Tight Oil plays, with approximately $58 million to be invested in development activities at Sleeping Giant with another $54 million on assessment activities in its new areas. Enerplus plans to drill 31 net wells across the entire Bakken portfolio and expects to refrac 11 net wells at the Sleeping Giant property. Enerplus also plans to continue testing multi-well, simultaneous fracturing as well increasing the number of fracture stages per well at Sleeping Giant with up to six simultaneous fracs and up to 12 frac stages. In addition, Enerplus plans to test a number of higher stage fracture stimulation projects in its new areas.

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Marcellus Shale Gas

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Overview

In 2009, Enerplus made a strategic investment in the Marcellus shale gas fairway gaining entry into one of the largest shale gas resource plays in North America. Spanning six states in the northeast U.S., the Marcellus shale play covers an estimated 95,000 square miles. With its proximity to the large northeast U.S. natural gas market, Marcellus natural gas receives a premium price, which when combined with an attractive cost structure provides the potential for superior economic returns compared to other natural gas producing areas in North America. For information on the acquisition of the Marcellus Properties effective September 1, 2009, see ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties ’’. Between the initial acquisition in September 2009 and year-end, Enerplus added 10,000 net acres to its position and swapped certain acreage to consolidate its position. Enerplus continues to pursue other opportunities to increase and consolidate its acreage and potentially add an operated position in the area.

At December 31, 2009, Enerplus owned an average 23.6% non-operated working interest in approximately 534,000 acres of land. The majority of the land is concentrated in the northeast and southwest areas of Pennsylvania with additional acreage located in West Virginia and Maryland. Much of the acreage is contiguous and the majority of the leases allow extensions of the primary term (which have an average term of approximately five years) for an additional five years.

From the time that Enerplus entered the Marcellus shale gas play in September 2009 to year-end, it invested a total of $29 million on the play: $12 million representing Enerplus’ share of capital, $12 million on the Marcellus Carry Amount which covers 50% of Chief’s (Enerplus’ partner) capital costs, and $5 million for the purchase of additional acreage and seismic data. Enerplus had anticipated that 15 wells would be drilled and seven wells would be completed by the end of 2009, however only 12 wells were drilled and five wells were completed due to scheduling of tie-ins and availability of services at the end of the year. Enerplus anticipates that substantial progress will be made in the

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installation of gathering infrastructure in Lycoming County, Pennsylvania and Marshall County, West Virginia by early in the second quarter of 2010. Chief is focused on securing the required services to advance the completion programs. However, continued increases in industry activity could put additional pressure on costs and the timing of Enerplus’ programs going forward.

At year end 2009, the Marcellus Properties had a total of 43 gross wells drilled with 11 wells on production, 22 wells waiting to be completed and 10 wells awaiting tie-in. Enerplus (through its operator, Chief) currently has four rigs working in the Marcellus play with a fifth rig expected early in the second quarter of 2010. Enerplus plans to drill and complete 12 gross wells and tie-in 8 additional wells during the first quarter of 2010. Daily production averaged 2.1 MMcfe/d net to Enerplus during the month of December. Based on current development plans, Enerplus expects its working interest share of gross production volumes to increase to approximately 100 MMcf/d of natural gas over the next four years.

Enerplus intends to spend approximately $80 million in development capital on its Marcellus Shale Gas resource play in 2010, plus an additional $64 million as part of the Marcellus Carry Amount.

The independent Haas Report has assigned 8.1 Bcfe of Proved Reserves and 24.9 Bcfe of Proved plus Probable Reserves to Enerplus’ interest in the Marcellus Properties as of December 31, 2009. This represents an increase of over 200% from Enerplus’ internal estimate of the Proved plus Probable Reserves effective July 2009 conducted in connection with the Marcellus Acquisition.

Haas has also conducted an independent assessment of the contingent resources attributable to Enerplus’ interests in the Marcellus Properties and has provided a ‘‘best estimate’’ of natural gas contingent resources of approximately 2.1 Tcfe at December 31, 2009. This estimate assumes a land utilization rate of 55% and that the average well would produce approximately 3.4 Bcf per well, with the higher prospective areas producing approximately 5 Bcf per well. Enerplus expects recoveries to average approximately 30% with an average well density of 4 to 8 wells per section. Enerplus continues to see upside in the percentage of land that could be developed over time as delineation results continue to come in.

The contingent resource estimate for the Marcellus Properties 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% 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.

There is no certainty that it will be commercially viable to produce, or 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 Marcellus Properties as ‘‘reserves’’ consist of: additional delineation drilling to establish economic productivity in the development areas, limitations to development based on adverse topography or other surface restrictions, the uncertainty regarding marketing and transportation of natural gas from development areas, the receipt of all required regulatory permits and approvals to develop the land, and access to confidential information of other operators in the Marcellus formation. Significant negative factors related to the estimate include: the pace of development, including drilling and infrastructure, is slower than the forecast, risk of adverse regulatory and tax changes, ongoing litigation related to minimum royalties payable to freehold landowners and other issues related to gas development in populated areas. There are a number of inherent risks and contingencies associated with the development of the acquired interests in the Marcellus Properties including commodity price fluctuations, project costs, Enerplus’ ability to make the necessary capital expenditures to develop the properties, reliance on Enerplus’ industry partners in project development, acquisitions, funding and provisions of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described above and under ‘‘ Risk Factors ’’ in this Annual Information Form.

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’’.

Description of the Marcellus JDA and Related Commercial Arrangements

Under the terms of the Marcellus JDA, until the full Marcellus Carry Amount has been spent by Enerplus, Chief has the sole right to propose the drilling and development of wells on the Marcellus Properties and Enerplus is required to participate in those operations (subject to certain exceptions, including limitations on wells drilled subsequent to an initial well being drilled in an area or when the Marcellus Vendors

14 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

have failed to conduct sufficient drilling activities as set out in the Marcellus JDA), and the operations on the Marcellus Properties will be conducted in accordance with a mutually agreed-upon development plan. Subject to certain cure provisions, if Enerplus defaults in its obligations to pay the required portion of the Marcellus Carry Amount on behalf of the Marcellus Vendors, in addition to other remedies available to the Marcellus Vendors, Enerplus will be required to reassign to the Marcellus Vendors all of its interests in the area where the proposed well was located, other than in respect of any existing wellbores located in the area in which Enerplus owns an interest. Additionally, in such circumstances, the Marcellus Vendors will have the right to suspend some or all of the Marcellus Vendors’ obligations to Enerplus under the Marcellus JDA, including with respect to the sharing of certain information and the requirement to offer Enerplus its proportionate share of any subsequently-acquired interests pursuant to the Marcellus AMI Agreements, as defined and described below.

Following Enerplus’ expenditure of the required Marcellus Carry Amount, either of Enerplus or Chief can propose well drilling and development plans and the other party may elect whether or not it will participate in such drilling and development. If a party elects not to participate, the provisions of the operating agreement with respect to the applicable area will govern the rights and remedies between the parties.

The Marcellus JDA also includes area of mutual interest provisions (‘‘ Marcellus AMI Agreements ’’) with the Marcellus Vendors that will provide Enerplus the opportunity to partner with the Marcellus Vendors in any follow-on acquisitions or swaps in the Marcellus region. These Marcellus AMI Agreements will provide Enerplus with the opportunity to jointly acquire more land under the current ownership structure, as well as the potential to increase its working interest ownership on new lands and operate in certain new areas.

Enerplus has entered into long-term agreements for the gathering, dehydration and compression of Enerplus’ share of production from the Marcellus Properties. These agreements are intended to provide Enerplus with cost certainty and direct ties to the northeast United States natural gas markets through connections with major interstate pipelines.

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Tight Gas

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Enerplus’ Tight Gas resource play represented 18% of Enerplus’ average daily production in 2009 and 17% of its Proved plus Probable Reserves as at December 31, 2009. Enerplus’ highest producing tight natural gas properties in 2009 were its Tommy Lakes property in northern British Columbia and Pine Creek, Elmworth and Burnt Timber, all of which are located in Alberta. This play type includes multi-zone tight natural gas plays such as Cardium, Nikannassin, Montney, Bluesky, Nordegg and Halfway zones, as well as others.

Capital spending on Enerplus’ Tight Gas properties increased to $95 million in 2009. At Tommy Lakes, Enerplus completed a 14 well program which was started in late 2008, spending approximately $30 million. Approximately $40 million was invested on acquiring prospective land and to perform seismic and assessment drilling activities in the Deep Basin region of Alberta and British Columbia where Enerplus now has approximately 50 net sections of undeveloped land targeting the Montney, Nordegg and Mannville formations.

Enerplus expects to reduce spending on this play in 2010 to approximately $56 million as it is not planning a development program at Tommy Lakes given the current outlook for natural gas prices. Enerplus has plans to drill a number of assessment wells along with some seismic work on its newly acquired lands targeting formations with potential for multi-frac horizontal well drilling.

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Crude Oil Waterfloods

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In a Crude Oil Waterflood, water is injected into the formation to supplement the original reservoir pressure and provide a drive mechanism to move additional oil to producing wells. 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.

In 2009, Enerplus’ five largest waterflood producing properties were Pembina 5 Way, Joarcam, 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. Enerplus operates over 80% of its crude oil waterflood production. 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. Approximately 18% of Enerplus’ production for the year ended December 31, 2009 and approximately 28% of Enerplus’ Proved plus Probable Reserves as at December 31, 2009 were related to its crude oil waterflood assets.

Capital spending within Enerplus’ Crude Oil Waterflood portfolio was largely focused at Freda Lake, Virden, Giltedge, Pembina 5 Way and Medicine Hat. Approximately $14 million was spent on drilling 11 net wells, including seven horizontal wells. Maintenance projects, including facility and pipeline integrity upgrades, were also a significant part of Enerplus’ activities. In total, Enerplus invested $37 million in this resource play in 2009 and essentially maintained production levels year-over-year.

Assuming an improved outlook for crude oil prices relative to natural gas prices, Enerplus expects to significantly increase its capital spending in 2010 on its waterflood assets to approximately $96 million, net of estimated Alberta government drilling royalty credits of approximately $10 million. Enerplus plans to drill 38 net wells to optimize recovery at its Medicine Hat, Giltedge, Freda Lake, Cadogan and Virden properties. Enerplus also expects to advance its work on enhanced oil recovery pilots on its waterflood properties, which Enerplus anticipates will include at least one field pilot well to test the use of polymers to improve overall oil recovery.

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Shallow Gas

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Enerplus’ Shallow Gas resource play, which includes certain CBM properties, has been a core development play 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.

The key to success in the Shallow Gas play involves executing large, multi-well development programs efficiently and subsequently managing the post-drilling operations of these low pressure wells in a cost-effective manner.

Shallow natural gas represented approximately 25% of Enerplus’ average daily production volumes in 2009 and approximately 18% of Enerplus’ Proved plus Probable Reserves as at December 31, 2009. Approximately 85% of Enerplus’ shallow natural gas production is operated by Enerplus. In 2009, Enerplus’ five largest shallow natural gas producing properties were the Shackleton field in southwest Saskatchewan and the Bantry, Verger, Hanna Garden, and Medicine Hat South properties in Alberta. All of these properties have associated pipeline infrastructure and compression facilities.

Enerplus invested $61 million in its shallow gas natural assets in 2009, net of approximately $17 million in Alberta drilling royalty credits, with most of its spending at the Shackleton field in Saskatchewan and at Bantry, Verger and Hanna Garden in Alberta. Due to weakening gas prices in the second quarter of 2009, Enerplus suspended its summer drilling program at Shackleton, preserving its drilling inventory pending higher sustainable natural gas prices, and with the implementation of the Alberta royalty drilling incentive program, Enerplus shifted its shallow natural gas drilling to Alberta. In total, Enerplus drilled 259 net shallow natural gas wells, including 120 net wells that attracted drilling royalty credits.

With the current natural gas price outlook, Enerplus’ projected shallow natural gas spending for 2010 has been reduced to approximately $41 million, net of anticipated Alberta royalty drilling credits. Enerplus plans to drill approximately 156 net wells with a focus on infill drilling at Shackleton, Hanna Garden, Bantry and Verger. Enerplus believes these areas appear to offer the most attractive opportunities and allow Enerplus to take advantage of Alberta government drilling incentives of approximately $15 million. Enerplus anticipates that approximately 60% of its total wells drilled in 2010 will be shallow natural gas wells targeting the Milk River, Second White Specks and Medicine Hat formations.

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Oil Sands

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Enerplus’ Oil Sands portfolio currently includes its operated SAGD Kirby Project and its joint venture with and equity ownership in Laricina. Enerplus invested $15 million in its oil sands portfolio in 2009, the majority of which was spent at the Kirby Project to complete its seismic program and the work associated with obtaining regulatory approvals, as described below.

Kirby Project:

Enerplus acquired the Kirby Lease in 2007 for an aggregate purchase price of $203.1 million. The Kirby Project is a 100% owned and operated SAGD project which Enerplus currently believes has potential production capacity, through staged development, of up to 50,000 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 attributed to it, the independent GLJ Oil Sands Resources Report effective December 31, 2009 indicates a ‘‘best estimate’’ of 497 MMbbls of aggregate contingent bitumen resources within the Kirby Lease, as outlined in the table below. Enerplus’ development plan included developing the property in phases, with Phase 1 having production capability of 10,000 bbls/d of bitumen and Phases 2 and 3 each having incremental production capacity of 20,000 bbls/d of bitumen. Enerplus submitted the development application for Phase 1 to the regulatory authorities in September 2008 and continues to expect approval of its application for a 10,000 bbl/d in-situ oil sands project in 2010.

While Enerplus believes that the geologic characteristics, quality and potential of the Kirby Lease are attractive, Enerplus believes that the Kirby Project is not as compelling as other projects in its portfolio that have a shorter time frame to positive cash flow. Enerplus will continue to evaluate its options to maximize the value of this lease and expects only minimal spending on the Kirby Project in 2010.

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 as of December 31, 2009, 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. GLJ’s best estimate represents an approximate 20% increase from its best estimate at December 31, 2008 and a 104% increase since Enerplus acquired the lease in 2007. The increase at year-end 2009 was generally as result of additional information gathered from Enerplus’ seismic program conducted during 2009.

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% probability that the quantities actually recovered will equal or exceed the best

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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
	As of December 31, 2009
	(MMbbls)
Wabiskaw D Formation	233
McMurray North Formation	220
McMurray South Formation	24
Wabiskaw B Formation	20
Total Kirby Lease Contingent Resource Estimate	497

There is no certainty that it will be commercially viable to produce, or 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: further reservoir studies; delineation drilling; facility design; preparation of firm development plans including determination of the specific scope and timing of the project; requirement for regulatory approvals; the uncertainty regarding marketing plans for production from the subject areas; improved estimation of project costs; and Enerplus’ internal approvals. There are a number of inherent risks and contingencies associated with the development of the Kirby Project, including commodity price fluctuations, project costs and those other risks and contingencies described above and under ‘‘ Risk Factors ’’ in this Annual Information Form and particularly under ‘‘ Risk Factors – Risks Related to Enerplus’ Business and Operations – The development of the Kirby Project 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’’.

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 oil sands lease for approximately 20% equity value in Laricina. As at December 31, 2009, Enerplus owned approximately 11% of the total outstanding equity of Laricina. Included in the swap was an area of mutual interest agreement which was designed to allow Enerplus and Laricina to jointly pursue additional in-situ oil sands ventures. Enerplus participated in four land acquisitions with Laricina since entering the agreement, which has now expired.

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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 smaller working interests in both operated and non-operated crude oil and natural gas projects and consist of various reservoir types. Development capital was reduced by approximately 71% in 2009 to $30 million, given Enerplus’ desire to concentrate its capital spending and efforts in its core resource play areas. Enerplus has targeted a significant number of these properties for inclusion in its property divestment program. See ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Additional Strategic Acquisitions and Dispositions ’’.

Major conventional assets include the Brooks, Kingsford, Hayter, Enchant and Shorncliff properties in Alberta. Production from these other conventional oil and natural gas properties represented approximately 28% of Enerplus’ average daily production in 2009 and approximately 24% of Enerplus’ estimated total Proved plus Probable Reserves as of December 31, 2009.

Major facilities included in Enerplus’ conventional oil and natural gas properties include: (i) a 100% interest in Brooks North and South oil batteries and water disposal facilities, (ii) a 22% interest in the oil emulsion treating and water disposal facility at Hayter, Alberta; (iii) a 100% interest in three oil facilities at Shorncliff, (iv) a 75% interest in the Colgate oil battery, (v) a 15% interest in the Sylvan Lake gas plant, and (vi) an 8% interest in the Hanlan-Robb gas plant.

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QUARTERLY PRODUCTION HISTORY

The following table sets forth Enerplus’ average daily production volumes, on a company interest basis, for each fiscal quarter in 2009 and for the entire year, separately for production in Canada and the United States, and in total.

Country and Product Type	Year Ended December 31, 2009
	First Second Third Fourth Quarter Quarter Quarter Quarter 16,039 15,826 15,237 15,141 9,342 9,395 9,109 9,130 25,381 25,221 24,346 24,271 4,059 4,420 3,912 4,238 29,440 29,641 28,258 28,509 325,799 323,941 310,212 291,833 83,740 83,632 79,960 77,148 9,046 8,494 7,872 7,319 13,058 14,252 13,672 13,858 11,222 10,869 10,151 9,629 25,085 24,320 23,109 22,460 9,342 9,395 9,109 9,130 34,427 33,715 32,218 31,590 4,059 4,420 3,912 4,238 38,486 38,135 36,130 35,828 338,857 338,193 323,884 305,691 94,962 94,501 90,111 86,777	Total for Year
Canada Light and medium oil (bbls/d) Heavy oil (bbls/d)		15,557 9,243
Total crude oil (bbls/d) Natural gas liquids (bbls/d)		24,800 4,157
Total liquids (bbls/d) Natural gas (Mcf/d)		28,957 312,846
Total Canada (BOE/d)		81,098
United States Light and medium crude oil (bbls/d) Natural gas (Mcf/d)		8,184 13,724
Total United States (BOE/d)		10,471
Total Enerplus Light and medium oil (bbls/d) Heavy oil (bbls/d)		23,741 9,243
Total crude oil (bbls/d) Natural gas liquids (bbls/d)		32,984 4,157
Total liquids (bbls/d) Natural gas (Mcf/d)		37,141 326,570
Total Enerplus (BOE/d)		91,569

22 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

QUARTERLY NETBACK HISTORY

The following tables set forth Enerplus’ average netbacks received for each fiscal quarter in 2009 and for the entire year, separately for production in Canada and the United States. Netbacks are calculated on the basis of prices received before the effects of commodity derivative instruments but after transportation costs, 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.

Light and Medium Crude Oil($ per bbl)	Year Ended December 31, 2009
	First Second Third Fourth Quarter Quarter Quarter Quarter $ 45.11 $ 60.41 $ 67.00 $ 68.41 (6.50) (8.49) (11.84) (12.58) (19.84) (17.06) (18.87) (16.70) $ 18.77 $ 34.86 $ 36.29 $ 39.13 $ 40.04 $ 60.53 $ 65.47 $ 70.66 (9.00) (13.82) (15.12) (16.83) (4.71) (4.45) (4.37) (5.59) $ 26.33 $ 42.26 $ 45.98 $ 48.24 $ 43.28 $ 60.45 $ 66.48 $ 69.14 (7.40) (10.35) (12.96) (13.96) (14.39) (12.65) (13.93) (13.08) $ 21.49 $ 37.45 $ 39.59 $ 42.10	Total for Year
Canada Sales price(1) Royalties Production costs(2)		$ 60.11 (9.81) (18.12)
Netback		$ 32.18
United States Sales price(1) Royalties(3) Production costs(2)		$ 58.41 (13.50) (4.76)
Netback		$ 40.15
Total Enerplus Sales price(1) Royalties(3) Production costs(2)		$ 59.53 (11.08) (13.52)
Netback		$ 34.93

Heavy Oil($ per bbl)	Year Ended December 31, 2009
	First Second Third Fourth Quarter Quarter Quarter Quarter $ 40.09 $ 58.13 $ 61.04 $ 64.85 (7.27) (10.68) (12.31) (13.25) (14.09) (15.06) (15.07) (12.78) $ 18.73 $ 32.39 $ 33.66 $ 38.82	Total for Year
Canada/Total Enerplus Sales price(1) Royalties Production costs(2)		$ 56.03 (10.88) (14.25)
Netback		$ 30.90

Natural Gas Liquids($ per bbl)	Year Ended December 31, 2009
	First Second Third Fourth Quarter Quarter Quarter Quarter $ 40.59 $ 35.47 $ 32.59 $ 56.96 (11.30) (9.82) (9.16) (14.24) – – – – $ 29.29 $ 25.65 $ 23.43 $ 42.72	Total for Year
Canada/Total Enerplus Sales price(1) Royalties Production costs(2)		$ 41.54 (11.16) –
Netback		$ 30.38

(continues on next page)

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 23

Natural Gas($ per Mcf)	Year Ended December 31, 2009
	First Second Third Fourth Quarter Quarter Quarter Quarter $ 5.12 $ 3.45 $ 2.88 $ 3.95 (0.92) (0.57) (0.13) (0.19) (1.36) (1.51) (1.44) (1.36) $ 2.84 $ 1.37 $ 1.31 $ 2.40 $ 5.38 $ 4.34 $ 4.55 $ 6.20 (1.10) (0.98) (0.96) (1.24) – – – – $ 4.28 $ 3.36 $ 3.59 $ 4.96 $ 5.13 $ 3.49 $ 2.95 $ 4.06 (0.92) (0.58) (0.16) (0.24) (1.31) (1.45) (1.38) (1.30) $ 2.90 $ 1.46 $ 1.41 $ 2.52	Total for Year
Canada Sales price(1) Royalties Production costs(2)		$ 3.86 (0.46) (1.42)
Netback		$ 1.98
United States Sales price(1) Royalties(3) Production costs(2)		$ 5.11 (1.07) –
Netback		$ 4.04
Total Enerplus Sales price(1) Royalties(3) Production costs(2)		$ 3.91 (0.49) (1.36)
Netback		$ 2.06

Total Enerplus($ per BOE)	Year Ended December 31, 2009
	First Second Third Fourth Quarter Quarter Quarter Quarter $ 34.80 $ 33.34 $ 32.48 $ 39.14 (6.17) (5.52) (4.61) (5.55) (10.65) (10.77) (10.91) (9.93) $ 17.98 $ 17.05 $ 16.96 $ 23.66 $ 38.62 $ 53.04 $ 56.90 $ 62.63 (8.53) (12.09) (13.02) (14.58) (3.80) (3.47) (3.39) (4.25) $ 26.29 $ 37.48 $ 40.49 $ 43.80 $ 35.24 $ 35.60 $ 35.23 $ 41.75 (6.43) (6.28) (5.56) (6.56) (9.84) (9.93) (10.07) (9.30) $ 18.97 $ 19.39 $ 19.60 $ 25.89	Total for Year
Canada Sales price(1) Royalties Production costs(2)		$ 34.89 (5.47) (10.57)
Netback		$ 18.85
United States Sales price(1) Royalties(3) Production costs(2)		$ 52.39 (11.95) (3.72)
Netback		$ 36.72
Total Enerplus Sales price(1) Royalties(3) Production costs(2)		$ 36.89 (6.21) (9.79)
Netback		$ 20.89

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.

24 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

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 present value of the future asset retirement obligations associated with its property, plant and equipment. Enerplus estimates such costs through a model that incorporates data from Enerplus’ operating history, industry 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 $677 million on an undiscounted basis and $125 million discounted at 10%. The calculations of future net revenue under ‘‘ Oil and Natural Gas Reserves ’’ in this Annual Information Form exclude approximately $311 million on an undiscounted basis and $78 million discounted at 10% as these amounts represent costs for abandonment and reclamation of facilities and wells for which no reserves have been attributed. In the next three financial years, Enerplus anticipates that a total of approximately $49 million on an undiscounted basis and $43 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

TAX HORIZON

Canada

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. No material cash Canadian income taxes were paid by the Fund or its Canadian Operating Subsidiaries for the year ended December 31, 2009.

As described in further detail under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus’ Strategy Post-2010 ’’ 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 beginning in 2011 at the same effective tax rates as Canadian corporations. The most important variables that will determine the level of cash taxes incurred by Enerplus post-conversion will be the price of crude oil and natural gas, capital spending levels and the amount of tax pools and other deductions available.

Within the context of current commodity prices and capital spending plans, Enerplus does not expect to be taxable until 2013 to 2015. This future tax horizon will also fluctuate depending on the ultimate nature and timing of Enerplus’ acquisitions and dispositions. Once it is taxable, Enerplus expects that its capital spending will help shelter taxes and would expect cash taxes to average approximately 15% of cash flow, which is not dissimilar to other oil and gas production companies. If crude oil and natural gas prices were to strengthen beyond the levels anticipated by the current forward market, Enerplus’ tax pools would be utilized more quickly and it may experience higher than expected cash taxes or payment of such taxes in an earlier time period. However, Enerplus emphasizes that it is difficult to give guidance on future taxability as it operates within an industry that constantly changes given acquisitions, divestments, capital spending, distributions and overall commodity prices. See ‘‘ Risk Factors – Risks Related to Enerplus’ Business and Operations – Changes in tax or other laws may adversely affect unitholders .’’

United States

A total of $0.2 million of U.S. income related cash taxes were incurred with respect to U.S. operations during the year ended December 31, 2009. 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 10 to the Fund’s audited financial statements for the year ended December 31, 2009 and the information under the heading ‘‘Taxes’’ in the Fund’s management’s discussion and analysis for the year ended December 31, 2009.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 25

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 for crude oil and yearly contracts for NGLs 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 $59.53/bbl for its light and medium crude oil, $56.03/bbl for its heavy crude oil and $41.54/bbl for its NGLs for the year ended December 31, 2009, compared to $94.30/bbl for its light and medium crude oil, $80.15/bbl for its heavy crude oil and $68.93/bbl for its NGLs for the year ended December 31, 2008. Enerplus has a transportation commitment to deliver 1,698 bbls/d of Canadian production on the Plains Marketing Canada Joarcam Pipeline until March 31, 2010.

Natural Gas

In marketing its natural gas production Enerplus tries to achieve a mix of contracts and customers. Within its sales portfolio of aggregator, downstream and spot natural gas sales, Enerplus sold approximately 90% of its natural gas split evenly between the daily and monthly AECO market indices and 10% against monthly U.S.-based indices.

Enerplus’ percentage of 2009 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 38% compared to 45% in 2008. The average price received by Enerplus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2009 was $3.91/Mcf compared to $8.17/Mcf in the year ended December 31, 2008.

Enerplus holds multiple contracts of various terms for transportation on the major gathering pipeline systems within the western provinces. The contracts comprise approximately 132 MMcf/d in Alberta, 32 MMcf/d in British Columbia and approximately 46 MMcf/d in Saskatchewan. As of December 31, 2009, Enerplus held 9 MMcf/d of firm transportation commitments on the Alliance Pipeline, in effect until October 31, 2015, under which Enerplus delivers natural gas into the U.S. Midwest area. The remainder of Enerplus’ Canadian natural gas production is sold primarily in the provinces of Alberta, Saskatchewan and British Columbia at prevailing spot market prices. Enerplus has contracted gas gathering capacity for its Marcellus production of 4,500 MMbtu per day effective March 1, 2010, and increasing to 6,000 MMbtu per day on May 1, 2010.

Future Commitments and Forward Contracts

Enerplus may use various types of derivative 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 11 to the Fund’s audited annual consolidated financial statements for the year ended December 31, 2009 and under the headings ‘‘Pricing’’ and ‘‘Price Risk Management’’ in the Fund’s management’s discussion and analysis for the year ended December 31, 2009, 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.

26 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Oil and Natural Gas Reserves

SUMMARY OF RESERVES

All of Enerplus’ reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. McDaniel, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 90% of the net present value (discounted at 10%, using forecast prices and costs) of Enerplus’ Proved plus Probable Canadian conventional oil and natural gas reserves. Enerplus has evaluated the balance of the Canadian conventional properties using similar evaluation parameters, including the same forecast price, inflation and exchange rate assumptions utilized by McDaniel. McDaniel has reviewed Enerplus’ evaluation of these properties.

NSAI, independent petroleum consultants based in Dallas, Texas, have evaluated all of Enerplus’ oil and natural gas reserves located in the western United States. Haas, independent petroleum consultants based in Dallas, Texas, have evaluated all of Enerplus’ oil and natural gas reserves attributable to the Marcellus shale gas assets located in the northeastern United States. For consistency in Enerplus’ reserves reporting, each of NSAI and Haas used McDaniel’s forecast prices and inflation rates to prepare their reports. Enerplus used McDaniel’s forecast exchange rates set forth below to convert U.S. dollar amounts in the NSAI Report and Haas Report to Canadian dollar amounts for presentation in this Annual Information Form.

The following sections and tables summarize, as at December 31, 2009, Enerplus’ oil, NGLs and natural gas reserves and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions associated with such reserve estimates. All information relating to Canadian reserves is contained in the McDaniel Report and all information relating to United States reserves is aggregated from the NSAI Report and the Haas Report. 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.

For information relating to the changes in the volumes of Enerplus’ reserves from December 31, 2008 to December 31, 2009, see ‘‘– Reconciliation of Reserves ’’ below.

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. The Canadian federal government has implemented the SIFT Tax which is designed to tax income trusts, such as Enerplus, at the same effective tax rates as Canadian corporations beginning with the 2011 tax year. The after-tax estimates of the net present value of future net revenue from Enerplus’ reserves include the estimated impact of the SIFT Tax. For additional information, see ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years ’’, ‘‘ Business of Enerplus – 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 27

Summary of Oil and Gas Reserves As of December 31, 2009

Forecast Prices and Costs

RESERVES CATEGORY		OIL AND NATURAL GAS RESERVES
	Light & Medium Oil Company Interest Gross Net (Mbbls) (Mbbls) (Mbbls) 57,742 57,089 50,160 21,062 21,002 17,518 78,804 78,091 67,678 539 539 490 1,276 1,276 1,064 1,815 1,815 1,554 2,772 2,765 2,461 3,114 3,114 2,572 5,886 5,879 5,033 61,053 60,393 53,111 25,452 25,392 21,154 86,505 85,785 74,265 16,776 16,551 13,940 7,287 7,267 6,007 24,063 23,818 19,947 77,829 76,944 67,051 32,739 32,659 27,161 110,568 109,603 94,212	Heavy Oil Company Interest Gross Net (Mbbls) (Mbbls) (Mbbls) 29,613 29,583 24,611 – – – 29,613 29,583 24,611 438 438 372 – – – 438 438 372 4,380 4,380 3,560 – – – 4,380 4,380 3,560 34,431 34,401 28,543 – – – 34,431 34,401 28,543 12,347 12,338 9,924 – – – 12,347 12,338 9,924 46,778 46,739 38,467 – – – 46,778 46,739 38,467	Natural Gas Liquids
			Company Interest Gross Net
Proved Developed Producing Canada United States			(Mbbls) (Mbbls) (Mbbls) 9,879 9,721 6,739 76 – 76
Total			9,955 9,721 6,815
Proved Developed Non-Producing Canada United States			124 117 89 4 – 4
Total			128 117 93
Proved Undeveloped Canada United States			630 630 486 40 – 40
Total			670 630 526
Total Proved Canada United States			10,633 10,468 7,314 120 – 120
Total			10,753 10,468 7,434
Probable Canada United States			3,718 3,659 2,592 36 – 36
Total			3,754 3,659 2,628
Total Proved Plus Probable Canada United States			14,351 14,127 9,906 156 – 156
Total			14,507 14,127 10,062

(continues on next page)

28 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Summary of Oil and Gas Reserves As of December 31, 2009

Forecast Prices and Costs

(continued)

RESERVES CATEGORY		OIL AND NATURAL GAS RESERVES
	Natural Gas Company Interest Gross Net (MMcf) (MMcf) (MMcf) 624,588 608,201 522,773 39,554 30,810 34,294 664,142 639,011 557,067 13,444 13,297 11,236 1,770 1,303 1,554 15,214 14,600 12,790 58,553 58,424 50,114 8,125 3,574 7,497 66,678 61,998 57,611 696,585 679,922 584,123 49,449 35,687 43,345 746,034 715,609 627,468 250,061 244,873 209,237 17,085 13,137 14,770 267,146 258,010 224,007 946,646 924,795 793,360 66,534 48,824 58,115 1,013,180 973,619 851,475	Shale Gas Company Interest Gross Net (MMcf) (MMcf) (MMcf) – – – 2,914 2,914 2,350 2,914 2,914 2,350 – – – 626 626 510 626 626 510 – – – 4,587 4,587 3,709 4,587 4,587 3,709 – – – 8,127 8,127 6,569 8,127 8,127 6,569 – – – 16,763 16,763 13,545 16,763 16,763 13,545 – – – 24,890 24,890 20,114 24,890 24,890 20,114	Total
			Company Interest Gross Net
Proved Developed Producing Canada United States			(MBOE) (MBOE) (MBOE) 201,332 197,761 168,638 28,216 26,623 23,702
Total			229,548 224,384 192,340
Proved Developed Non-Producing Canada United States			3,341 3,309 2,824 1,679 1,597 1,412
Total			5,020 4,906 4,236
Proved Undeveloped Canada United States			17,541 17,512 14,859 5,273 4,475 4,479
Total			22,814 21,987 19,338
Total Proved Canada United States			222,214 218,582 186,321 35,168 32,695 29,593
Total			257,382 251,277 215,914
Probable Canada United States			74,518 73,361 61,329 12,964 12,249 10,762
Total			87,482 85,610 72,091
Total Proved Plus Probable Canada United States			296,732 291,943 247,650 48,132 44,944 40,355
Total			344,864 336,887 288,005

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 29

Summary of Net Present Value of Future Net Revenue

Attributable to Oil and Gas Reserves

As of December 31, 2009

Forecast Prices and Costs

		NET PRESENT VALUE OF FUTURE NET REVENUE	NET PRESENT VALUE OF FUTURE NET REVENUE	NET PRESENT VALUE OF FUTURE NET REVENUE	NET PRESENT VALUE OF FUTURE NET REVENUE	NET PRESENT VALUE OF FUTURE NET REVENUE	DISCOUNTED AT (%/YEAR)	DISCOUNTED AT (%/YEAR)	DISCOUNTED AT (%/YEAR)
	Before Deducting Income Taxes					After Deducting Income Taxes					Unit
RESERVES CATEGORY	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%	Value(1)
					(in $ millions)						($/BOE)
Proved developed producing
Canada	6,701	4,554	3,507	2,883	2,466	5,722	4,005	3,147	2,625	2,269	$ 20.80
United States	1,352	923	698	563	475	1,012	697	529	428	362	$ 29.45
Total	8,053	5,477	4,205	3,446	2,941	6,734	4,702	3,676	3,053	2,631	$ 21.86
Proved developed non-producing
Canada	105	79	64	53	44	79	60	49	41	36	$ 22.66
United States	77	58	44	36	29	46	34	27	21	17	$ 31.16
Total	182	137	108	89	73	125	94	76	62	53	$ 25.50
Proved undeveloped
Canada	380	242	160	107	71	224	129	74	40	17	$ 10.77
United States	175	107	71	48	34	124	80	55	40	30	$ 15.85
Total	555	349	231	155	105	348	209	129	80	47	$ 11.95
Total Proved
Canada	7,186	4,875	3,731	3,043	2,581	6,025	4,194	3,270	2,706	2,322	$ 20.02
United States	1,604	1,088	813	647	538	1,182	811	611	489	409	$ 27.47
Total	8,790	5,963	4,544	3,690	3,119	7,207	5,005	3,881	3,195	2,731	$ 21.05
Probable
Canada	2,990	1,449	877	601	444	2,200	1,068	646	443	327	$ 14.30
United States	705	326	190	129	95	445	205	112	73	52	$ 17.65
Total	3,695	1,775	1,067	730	539	2,645	1,273	758	516	379	$ 14.80
Total Proved Plus Probable
Canada	10,176	6,324	4,608	3,644	3,025	8,225	5,262	3,916	3,149	2,649	$ 18.61
United States	2,309	1,414	1,003	776	633	1,627	1,016	723	562	461	$ 24.85
Total	12,485	7,738	5,611	4,420	3,658	9,852	6,278	4,639	3,711	3,110	$ 19.48

Note:

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

30 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Summary of Oil and Gas Reserves As of December 31, 2009

Constant Prices and Costs

OIL AND NATURAL GAS RESERVES

RESERVES CATEGORY	Light & Medium Oil Company Interest Gross Net (Mbbls) (Mbbls) (Mbbls) 54,802 54,151 50,576 19,744 19,744 16,475 74,546 73,895 67,051 527 527 488 1,261 1,261 1,051 1,788 1,788 1,539 2,643 2,636 2,465 2,751 2,751 2,271 5,394 5,387 4,736 57,972 57,314 53,529 23,756 23,756 19,797 81,728 81,070 73,326 16,234 16,009 14,613 6,876 6,876 5,718 23,110 22,885 20,331 74,206 73,323 68,142 30,632 30,632 25,515 104,838 103,955 93,657	Heavy Oil Company Interest Gross Net (Mbbls) (Mbbls) (Mbbls) 29,025 28,995 24,917 – – – 29,025 28,995 24,917 428 428 379 – – – 428 428 379 4,315 4,315 3,632 – – – 4,315 4,315 3,632 33,768 33,738 28,928 – – – 33,768 33,738 28,928 12,155 12,147 10,381 – – – 12,155 12,147 10,381 45,923 45,885 39,309 – – – 45,923 45,885 39,309	Natural Gas Liquids
			Company Interest Gross Net
Proved Developed Producing Canada United States			(Mbbls) (Mbbls) (Mbbls) 8,683 8,517 5,944 74 – 74
Total			8,757 8,517 6,018
Proved Developed Non-Producing Canada United States			110 102 80 4 – 4
Total			114 102 84
Proved Undeveloped Canada United States			60 60 43 36 – 36
Total			96 60 79
Total Proved Canada United States			8,853 8,679 6,067 114 – 114
Total			8,967 8,679 6,181
Probable Canada United States			2,776 2,719 1,917 27 – 27
Total			2,803 2,719 1,944
Total Proved Plus Probable Canada United States			11,629 11,398 7,984 141 – 141
Total			11,770 11,398 8,125

(continues on next page)

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 31

Summary of Oil and Gas Reserves As of December 31, 2009

Constant Prices and Costs (continued)

RESERVES CATEGORY		OIL AND NATURAL GAS RESERVES
	Natural Gas Company Interest Gross Net (MMcf) (MMcf) (MMcf) 529,262 513,001 461,263 36,587 28,232 31,851 565,849 541,233 493,114 9,018 8,871 7,483 1,742 1,278 1,530 10,760 10,149 9,013 6,764 6,648 5,666 7,157 3,009 6,627 13,921 9,657 12,293 545,044 528,520 474,412 45,486 32,519 40,008 590,530 561,039 514,420 170,186 165,128 149,077 14,856 11,962 12,824 185,042 177,090 161,901 715,230 693,648 623,489 60,342 44,481 52,832 775,572 738,129 676,321	Shale Gas Company Interest Gross Net (MMcf) (MMcf) (MMcf) – – – 2,722 2,722 2,195 2,722 2,722 2,195 – – – 595 595 485 595 595 485 – – – 3,757 3,757 3,037 3,757 3,757 3,037 – – – 7,074 7,074 5,717 7,074 7,074 5,717 – – – 16,151 16,151 13,048 16,151 16,151 13,048 – – – 23,225 23,225 18,765 23,225 23,225 18,765	Total
			Company Interest Gross Net
Proved Developed Producing Canada United States			(MBOE) (MBOE) (MBOE) 180,721 177,164 158,314 26,369 24,903 22,222
Total			207,090 202,067 180,536
Proved Developed Non-Producing Canada United States			2,568 2,535 2,194 1,654 1,573 1,392
Total			4,222 4,108 3,586
Proved Undeveloped Canada United States			8,145 8,119 7,084 4,607 3,879 3,919
Total			12,752 11,998 11,003
Total Proved Canada United States			191,434 187,818 167,592 32,630 30,355 27,533
Total			224,064 218,173 195,125
Probable Canada United States			59,529 58,396 51,758 12,071 11,562 10,056
Total			71,600 69,958 61,814
Total Proved Plus Probable Canada United States			250,963 246,214 219,350 44,701 41,917 37,589
Total			295,664 288,131 256,939

32 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Summary of Net Present Value of Future Net Revenue

Attributable to Oil and Gas Reserves

As of December 31, 2009

Constant Prices and Costs

		NET PRESENT VALUE OF FUTURE NET	NET PRESENT VALUE OF FUTURE NET	NET PRESENT VALUE OF FUTURE NET	NET PRESENT VALUE OF FUTURE NET	REVENUE	DISCOUNTED AT (%/YEAR)	DISCOUNTED AT (%/YEAR)	DISCOUNTED AT (%/YEAR)
	Before Deducting Income Taxes					After Deducting Income Taxes					Unit
RESERVES CATEGORY	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%	Value(1)
					(in $ millions)						($/BOE)
Proved Developed Producing
Canada	2,863	2,111	1,706	1,449	1,269	2,709	2,024	1,651	1,412	1,243	$10.78
United States	671	506	408	343	298	541	411	332	280	244	$18.36
Total	3,534	2,617	2,114	1,792	1,567	3,250	2,435	1,983	1,692	1,487	$11.71
Proved Developed Non-Producing
Canada	48	39	31	27	24	43	35	28	23	21	$14.12
United States	41	31	24	20	16	29	21	16	13	10	$17.25
Total	89	70	55	47	40	72	56	44	36	31	$15.34
Proved Undeveloped
Canada	158	101	68	46	31	116	71	45	29	17	$ 9.60
United States	47	24	10	1	(5)	37	20	9	2	(4)	$ 2.55
Total	205	125	78	47	26	153	91	54	31	13	$ 7.09
Total Proved
Canada	3,069	2,251	1,805	1,522	1,324	2,868	2,130	1,724	1,464	1,281	$10.77
United States	759	561	442	364	309	607	452	357	295	250	$16.05
Total	3,828	2,812	2,247	1,886	1,633	3,475	2,582	2,081	1,759	1,531	$11.52
Probable
Canada	1,116	602	392	282	216	875	493	328	240	185	$ 7.57
United States	254	137	86	60	45	179	97	58	39	29	$ 8.55
Total	1,370	739	478	342	261	1,054	590	386	279	214	$ 7.73
Total Proved Plus Probable
Canada	4,185	2,853	2,197	1,804	1,540	3,743	2,623	2,052	1,704	1,466	$10.02
United States	1,013	698	528	424	354	786	549	415	334	279	$14.05
Total	5,198	3,551	2,725	2,228	1,894	4,529	3,172	2,467	2,038	1,745	$10.61

Note:

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

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 33

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 McDaniel as of January 1, 2010 (and utilized by NSAI and Haas for consistency in Enerplus’ reserves reporting) and the following inflation and exchange rate assumptions:

Year	CRUDE OIL WTI Edmonton Hardisty Cromer Cushing Par Price Heavy Medium Oklahoma 40�API(1) 12�API 29.3�API ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) 80.00 83.20 68.10 76.50 83.60 87.00 67.60 79.10 87.40 91.00 68.00 81.80 91.30 95.00 68.10 85.40 95.30 99.20 71.10 89.20 (2) (2) (2) (2)	NATURAL GAS 30 day Henry spot Hub @ AECO Price ($Cdn/MMbtu) ($US/MMbtu) 6.05 6.05 6.75 6.90 7.15 7.30 7.45 7.70 7.80 8.15 (2) (2)	NATURAL GAS LIQUIDS Edmonton Par Price Pentanes Propanes Butanes Plus ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) 46.40 64.00 85.20 49.50 66.90 89.00 52.00 70.00 93.80 54.30 73.10 97.10 56.70 76.30 101.40 (2) (2) (2)	Inflation Exchange Rate Rate
2010 2011 2012 2013 2014 Thereafter				(%/year) ($US/$Cdn) 2.0 0.95 2.0 0.95 2.0 0.95 2.0 0.95 2.0 0.95 2.0 0.95

Notes:

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

(2) Escalation is approximately 4% per year to 2015, and then approximately 2% per year thereafter.

In 2009, Enerplus received a weighted average price (net of transportation costs but before hedging) of $56.03/bbl for heavy crude oil, $59.53/bbl for light and medium crude oil, $41.54/bbl for NGLs and $3.91/Mcf for natural gas.

CONSTANT PRICES AND COSTS

The constant price and cost case is based upon an unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the company’s fiscal year-end as at December 31, 2009, held constant throughout the estimated lives of the properties to which the estimate applies, and assumes the continuance of operating costs projected for 2010 and the continuance of current laws and regulations. Product prices have not been escalated 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 constant prices determined as at December 31, 2009 and the following exchange rate assumptions:

Year	CRUDE OIL WTI Edmonton Hardisty Cromer Cushing Par Price Heavy Medium Oklahoma 40�API(1) 12�API 29.3�API ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) 61.18 65.21 59.38 62.02	NATURAL GAS 30 day Henry spot Hub @ AECO Price ($Cdn/MMbtu) ($US/MMbtu) 3.77 3.82	NATURAL GAS LIQUIDS Edmonton Par Price Pentanes Propanes Butanes Plus ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) 37.36 46.52 68.71	Inflation Exchange Rate Rate
Constant				(%/year) ($US/$Cdn) – 0.869

Note:

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

34 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2009, using forecast prices and costs, is set forth below (columns or rows may not add due to rounding):

					Abandon-	Future Net		Future Net
		Royalties			ment	Revenue		Revenue
		and		Develop-	and	Before		After
		Production	Operating	ment	Reclamation	Income	Income	Income
Reserves Category	Revenue	Taxes	Costs	Costs	Costs	Taxes	Taxes	Taxes
				(in $	millions)
Proved Reserves
Canada	15,809	2,499	5,257	582	286	7,186	1,161	6,025
United States	2,933	757	464	79	28	1,604	422	1,182
Total	18,743	3,255	5,722	661	314	8,790	1,583	7,207
Proved Plus Probable Reserves
Canada	22,047	3,616	7,183	739	332	10,176	1,951	8,225
United States	4,207	1,086	676	103	34	2,309	682	1,627
Total	26,254	4,701	7,859	842	366	12,485	2,633	9,852

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, 2009, using forecast prices and costs and discounted at 10% per year, is set forth below:

Reserves Category	Net Present Value of Future Net Revenue Before Income Taxes Production Group (Discounted at 10%/year) Unit Value(3)
Canada Proved Reserves	(in $ millions) ($/Bbl/$/Mcf) Light and Medium Crude Oil(1) 1,389 $26.30/bbl Heavy Oil(1) 762 $26.71/bbl Natural Gas(2) 1,580 $2.96/Mcf Shale Gas(2) – – Total 3,731
Proved Plus Probable Reserves	Light and Medium Crude Oil(1) 1,659 $24.88/bbl Heavy Oil(1) 938 $24.40/bbl Natural Gas(2) 2,011 $2.76/Mcf Shale Gas(2) – – Total 4,608
United States Proved Reserves	Light and Medium Crude Oil(1) 740 $29.09/bbl Heavy Oil(1) – – Natural Gas(2) 58 $4.21/Mcf Shale Gas(2) 15 $1.86/Mcf Total 813
Proved Plus Probable Reserves	Light and Medium Crude Oil(1) 883 $26.97/bbl Heavy Oil(1) – – Natural Gas(2) 71 $4.05/Mcf Shale Gas(2) 49 $1.96/Mcf Total 1,003
Total Enerplus Proved Reserves	Light and Medium Crude Oil(1) 2,129 $27.21/bbl Heavy Oil(1) 762 $26.71/bbl Natural Gas(2) 1,638 $2.99/Mcf Shale Gas(2) 15 $1.86/Mcf Total 4,544
Proved Plus Probable Reserves	Light and Medium Crude Oil(1) 2,542 $25.57/bbl Heavy Oil(1) 938 $24.40/bbl Natural Gas(2) 2,082 $2.79/Mcf Shale Gas(2) 49 $1.96/Mcf Total 5,611

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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 35

ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

The volume of production estimated for 2010 in preparing the estimates of gross Proved Reserves and gross Probable Reserves is set forth below. Canadian production has been estimated by McDaniel and U.S. production has been estimated by NSAI and Haas. Columns may not add due to rounding.

Product Type	Gross Proved Reserves	Gross Proved Reserves
	Canada Estimated 2010 Estimated 2010 Aggregate Average Daily Production Production 5,091 Mbbls 13,948 bbls/d 3,531 Mbbls 9,674 bbls/d 8,622 Mbbls 23,622 bbls/d 1,301 Mbbls 3,565 bbls/d 9,924 Mbbls 27,188 bbls/d 94,599 MMcf 259,176 Mcf/d – – 25,690 MBOE 70,384 BOE/d	United States
		Estimated 2010 Estimated 2010 Aggregate Average Daily Production Production
Crude Oil Light and Medium Crude Oil Heavy Oil		2,876 Mbbls 7,878 bbls/d – –
Total Crude Oil Natural Gas Liquids		2,876 Mbbls 7,878 bbls/d 13 Mbbls 34 bbls/d
Total Liquids Natural Gas Shale Gas		2,888 Mbbls 7,912 bbls/d 4,867 MMcf 13,335 Mcf/d 616 MMcf 1,689 Mcf/d
Total		3,802 MBOE 10,416 BOE/d

Product Type	Gross Probable Reserves	Gross Probable Reserves
	Canada Estimated 2010 Estimated 2010 Aggregate Average Daily Production Production 167 Mbbls 459 bbls/d 166 Mbbls 456 bbls/d 334 Mbbls 914 bbls/d 61 Mbbls 165 bbls/d 393 Mbbls 1,078 bbls/d 3,985 MMcf 10,917 Mcf/d – – 1,058 MBOE 2,898 BOE/d	United States
		Estimated 2010 Estimated 2010 Aggregate Average Daily Production Production
Crude Oil Light and Medium Crude Oil Heavy Oil		228 Mbbls 626 bbls/d – –
Total Crude Oil Natural Gas Liquids		228 Mbbls 626 bbls/d – 1 bbl/d
Total Liquids Natural Gas Shale Gas		228 Mbbls 627 bbls/d 324 MMcf 886 Mcf/d 801 MMcf 2,193 Mcf/d
Total		416 MBOE 1,140 BOE/d

FUTURE DEVELOPMENT COSTS

The amount of development costs deducted in the estimation of net present value of future net revenue is set forth below. Enerplus intends to fund its development activities through internally generated cash flow, as well as through debt or the issuance of Trust Units where required. Enerplus does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on Enerplus’ disclosed oil and gas reserves or future net revenue attributable to those reserves. For additional information, see ‘‘ Business of Enerplus – Capital Expenditures and Costs Incurred ’’ and ‘‘ Business of Enerplus – Exploration and Development Activities ’’:

Year	CANADA UNITED Proved Plus Proved Reserves Probable Reserves Proved Reserves Discounted Discounted Discounted Undiscounted at 10%/year Undiscounted at 10%/year Undiscounted at 10%/year (in $ millions) 150 143 168 160 69 66 142 123 192 166 3 3 113 89 138 109 7 5 50 36 107 77 – – 25 16 33 22 – – 102 42 101 40 – – 582 449 739 574 79 74	UNITED	STATES
	Proved Reserves Discounted Undiscounted at 10%/year	Proved Reserves Discounted Undiscounted at 10%/year	Proved Plus Probable Reserves
			Discounted Undiscounted at 10%/year
2010 2011 2012 2013 2014 Remainder	150 143 142 123 113 89 50 36 25 16 102 42		83 79 3 3 7 5 9 6 1 1 – –
Total	582 449	79 74	103 94

36 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

RECONCILIATION OF RESERVES

Overview

Enerplus experienced negative reserve revisions in 2009. The negative reserve revisions were associated with both Enerplus’ Proved Reserves and Probable Reserves and resulted from the removal of undeveloped drilling locations, changes in evaluation methodology, reservoir performance and the decline in natural gas prices. In total, approximately 0.37 Tcf of natural gas reserves, representing approximately 25% of Enerplus’ total 2008 year-end natural gas bookings, and approximately 6 MMBOE of crude oil and NGLs reserves, representing approximately 3% of Enerplus’ total 2008 year-end crude oil and NGLs reserves, were impacted, representing approximately 16% of Enerplus’ total Proved plus Probable Reserves.

Approximately 42% of the revisions were attributable to the removal of approximately 1,400 undeveloped drilling locations and a reduction in the reserves attributable to the remaining undeveloped drilling locations. The majority of these revisions were in Enerplus’ shallow natural gas resource properties. In total, approximately 0.15 Tcfe of reserves associated with Enerplus’ natural gas properties and 3 MMBOE of reserves associated with Enerplus’ crude oil properties were impacted by this factor. After revisions, Enerplus now has approximately 1,000 future drilling locations in its reserve evaluations with close to 700 of those being shallow natural gas locations. Although Enerplus has not booked many Marcellus Shale Gas or Canadian Tight Gas drilling locations, the significant reduction in shallow natural gas locations was driven by Enerplus’ belief that it will direct a majority of its spending toward the higher impact Marcellus and Canadian tight gas plays as well as crude oil properties. Enerplus’ inventory of undeveloped oil drilling locations remains at approximately 200 locations, with only limited locations related to its Bakken/Tight Oil growth areas at this time.

Methodology changes used by Enerplus’ new independent Canadian conventional reserve evaluators, McDaniel (who replaced Sproule Associates Limited in August 2009), accounted for approximately 27% of the reduction, or approximately 0.10 Tcfe from natural gas properties (primarily shallow natural gas) and 1.6 MMBOE from crude oil properties. The methodology changes included a different assessment of final economic producing rates and decline factors than were previously used. Maintenance capital requirements were also increased to include ten additional years (increased from 10 to 20 years) and an increased amount per year, resulting in approximately $140 million ($70 million of net present value discounted at 10%) of additional future development capital requirements.

Performance issues accounted for 28% of the reduction, consisting of approximately 0.10 Tcfe associated primarily with Enerplus’ shallow natural gas and 2.2 MMBOE associated with Enerplus’ crude oil properties. Lower than anticipated infill well performance and increased interference between wells has steepened the decline of Enerplus’ shallow natural gas properties.

The following tables reconcile Enerplus’ oil and natural gas reserves (on both a company interest and a gross reserves basis) from December 31, 2008 to December 31, 2009, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

Reconciliation of Company Interest Reserves

Canadian Oil and Gas Reserves

CANADA Factors	Light & Medium Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 68,425 19,274 87,699 413 170 583 (1,090) (279) (1,369) – – – 921 269 1,190 197 (2) 195 (2,135) (2,656) (4,791) (5,678) – (5,678) 61,053 16,776 77,829	Heavy Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 33,139 12,790 45,929 – – – – – – – – – 947 831 1,778 (18) 3 (15) 3,737 (1,277) 2,460 (3,374) – (3,374) 34,431 12,347 46,778	Natural Gas Liquids
			Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(Mbbls) (Mbbls) (Mbbls) 12,939 4,714 17,653 5 3 8 (42) (11) (53) – – – 102 87 189 (73) (19) (92) (781) (1,056) (1,837) (1,517) – (1,517)
December 31, 2009			10,633 3,718 14,351

(continues on next page)

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 37

Reconciliation of Company Interest Reserves (continued)

CANADA Factors	Associated and Non-Associated Gas (Natural Gas) Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) 1,025,866 397,651 1,423,517 276 171 447 (755) (130) (885) 358 89 447 5,941 7,918 13,859 (10,072) (4,395) (14,467) (210,840) (151,243) (362,083) (114,189) – (114,189) 696,585 250,061 946,646	Shale Gas Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) – – – – – – – – – – – – – – – – – – – – – – – – – – –	Total
			Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(MBOE) (MBOE) (MBOE) 285,481 103,053 388,534 465 201 666 (1,257) (312) (1,569) 61 13 74 2,959 2,508 5,467 (1,572) (751) (2,323) (34,322) (30,194) (64,516) (29,601) – (29,601)
December 31, 2009			222,214 74,518 296,732

United States Oil and Gas Reserves

UNITED STATES Factors	Light & Medium Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 26,128 6,867 32,995 – – – – – – 434 657 1,091 2,378 731 3,109 – – – (514) (968) (1,482) (2,974) – (2,974) 25,452 7,287 32,739	Heavy Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) – – – – – – – – – – – – – – – – – – – – – – – – – – –	Natural Gas Liquids
			Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(Mbbls) (Mbbls) (Mbbls) 113 51 164 – – – – – – – – – 4 3 7 – – – 16 (18) (2) (13) – (13)
December 31, 2009			120 36 156

UNITED STATES Factors	Associated and Non-Associated Gas (Natural Gas) Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) 40,668 23,483 64,151 – – – – – – 591 970 1,561 2,949 1,289 4,238 – – – 10,063 (8,657) 1,406 (4,822) – (4,822) 49,449 17,085 66,534	Shale Gas Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) – – – 5,000 2,980 7,980 – – – – – – 3,313 13,773 17,086 – – – 2 10 12 (188) – (188) 8,127 16,763 24,890	Total Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(MBOE) (MBOE) (MBOE) 33,019 10,832 43,851 833 497 1,330 – – – 532 819 1,351 3,425 3,245 6,670 – – – 1,181 (2,429) (1,248) (3,822) – (3,822)
December 31, 2009			35,168 12,964 48,132

(continues on next page)

38 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Reconciliation of Company Interest Reserves (continued)

Total Oil and Gas Reserves

TOTAL Factors	Light & Medium Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 94,553 26,141 120,694 413 170 583 (1,090) (279) (1,369) 434 657 1,091 3,299 1,000 4,299 197 (2) 195 (2,649) (3,624) (6,273) (8,652) – (8,652) 86,505 24,063 110,568	Heavy Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 33,139 12,790 45,929 – – – – – – – – – 947 831 1,778 (18) 3 (15) 3,737 (1,277) 2,460 (3,374) – (3,374) 34,431 12,347 46,778	Natural Gas Liquids Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(Mbbls) (Mbbls) (Mbbls) 13,052 4,765 17,817 5 3 8 (42) (11) (53) – – – 106 90 196 (73) (19) (92) (765) (1,074) (1,839) (1,530) – (1,530)
December 31, 2009			10,753 3,754 14,507

TOTAL Factors	Associated and Non Associated Gas (Natural Gas) Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) 1,066,534 421,134 1,487,668 275 171 447 (755) (130) (885) 949 1,059 2,008 8,890 9,207 18,097 (10,072) (4,395) (14,467) (200,777) (159,900) (360,677) (119,011) – (119,011) 746,034 267,146 1,013,180	Shale Gas Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) – – – 5,000 2,980 7,980 – – – – – – 3,313 13,773 17,086 – – – 2 10 12 (188) – (188) 8,127 16,763 24,890	Total Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(MBOE) (MBOE) (MBOE) 318,500 113,885 432,385 1,298 698 1,996 (1,257) (312) (1,569) 593 832 1,425 6,384 5,753 12,137 (1,572) (751) (2,323) (33,141) (32,623) (65,764) (33,423) – (33,423)
December 31, 2009			257,382 87,482 344,864

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 39

Reconciliation of Gross Reserves

Canadian Oil and Gas Reserves

CANADA Factors	Light & Medium Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 67,720 19,045 86,765 413 170 583 (1,090) (279) (1,369) – – – 900 265 1,165 197 (2) 195 (2,168) (2,648) (4,816) (5,579) – (5,579) 60,393 16,551 76,944	Heavy Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 33,104 12,765 45,869 – – – – – – – – – 947 831 1,778 (18) 3 (15) 3,716 (1,261) 2,455 (3,348) – (3,348) 34,401 12,338 46,739	Natural Gas Liquids Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(Mbbls) (Mbbls) (Mbbls) 12,738 4,648 17,386 5 3 8 (42) (11) (53) – – – 94 85 179 (73) (19) (92) (768) (1,047) (1,815) (1,486) – (1,486)
December 31, 2009			10,468 3,659 14,127

CANADA Factors	Associated and Non-Associated Gas (Natural Gas) Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) 1,006,044 391,623 1,397,667 276 171 447 (755) (130) (885) 358 89 447 5,603 7,815 13,418 (10,072) (4,395) (14,467) (210,867) (150,300) (361,167) (110,665) – (110,665) 679,922 244,873 924,795	Shale Gas Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) – – – – – – – – – – – – – – – – – – – – – – – – – – –	Total Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(MBOE) (MBOE) (MBOE) 281,236 101,729 382,965 465 201 666 (1,257) (312) (1,569) 61 13 74 2,875 2,484 5,359 (1,572) (751) (2,323) (34,368) (30,003) (64,371) (28,858) – (28,858)
December 31, 2009			218,582 73,361 291,943

United States Oil and Gas Reserves

UNITED STATES Factors	Light & Medium Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 26,070 6,850 32,920 – – – – – – 434 657 1,091 2,378 731 3,109 – – – (550) (971) (1,521) (2,940) – (2,940) 25,392 7,267 32,659	Heavy Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) – – – – – – – – – – – – – – – – – – – – – – – – – – –	Natural Gas Liquids Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(Mbbls) (Mbbls) (Mbbls) – – – – – – – – – – – – – – – – – – – – – – – –
December 31, 2009			– – –

(continues on next page)

40 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Reconciliation of Gross Reserves (continued)

UNITED STATES Factors	Associated and Non-Associated Gas (Natural Gas) Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) 27,971 17,702 45,673 – – – – – – 591 970 1,561 2,528 933 3,461 – – – 8,215 (6,468) 1,747 (3,618) – (3,618) 35,687 13,137 48,824	Shale Gas Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) – – – 5,000 2,980 7,980 – – – – – – 3,313 13,773 17,086 – – – 2 10 12 (188) – (188) 8,127 16,763 24,890	Total Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(MBOE) (MBOE) (MBOE) 30,731 9,801 40,532 833 497 1,330 – – – 532 819 1,351 3,351 3,183 6,534 – – – 822 (2,051) (1,229) (3,574) – (3,574)
December 31, 2009			32,695 12,249 44,944

Total Oil and Gas Reserves

TOTAL Factors	Light & Medium Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 93,790 25,895 119,685 413 170 583 (1,090) (279) (1,369) 434 657 1,091 3,278 996 4,274 197 (2) 195 (2,718) (3,619) (6,337) (8,519) – (8,519) 85,785 23,818 109,603	Heavy Oil Proved Plus Proved Probable Probable (Mbbls) (Mbbls) (Mbbls) 33,104 12,765 45,869 – – – – – – – – – 947 831 1,778 (18) 3 (15) 3,716 (1,261) 2,455 (3,348) – (3,348) 34,401 12,338 46,739	Natural Gas Liquids Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(Mbbls) (Mbbls) (Mbbls) 12,738 4,648 17,386 5 3 8 (42) (11) (53) – – – 94 85 179 (73) (19) (92) (768) (1,047) (1,815) (1,486) – (1,486)
December 31, 2009			10,468 3,659 14,127

TOTAL Factors	Associated and Non-Associated Gas (Natural Gas) Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) 1,034,015 409,325 1,443,340 276 171 447 (755) (130) (885) 949 1,059 2,008 8,131 8,748 16,879 (10,072) (4,395) (14,467) (202,652) (156,768) (359,420) (114,283) – (114,283) 715,609 258,010 973,619	Shale Gas Proved Plus Proved Probable Probable (MMcf) (MMcf) (MMcf) – – – 5,000 2,980 7,980 – – – – – – 3,313 13,773 17,086 – – – 2 10 12 (188) – (188) 8,127 16,763 24,890	Total Proved Plus Proved Probable Probable
December 31, 2008 Acquisitions Divestments Discoveries Extensions and Improved Recovery Economic Factors Technical Revisions Production			(MBOE) (MBOE) (MBOE) 311,967 111,530 423,497 1,298 698 1,996 (1,257) (312) (1,569) 593 832 1,425 6,226 5,667 11,893 (1,572) (751) (2,323) (33,546) (32,054) (65,600) (32,432) – (32,432)
December 31, 2009			251,277 85,610 336,887

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 41

UNDEVELOPED RESERVES

The following tables disclose the volumes of Proved Undeveloped Reserves and Probable Undeveloped Reserves of Enerplus that were first attributed in the years indicated.

Proved Undeveloped Reserves

Year(1)	Crude Oil Light & Heavy Medium Bitumen (Mbbls) (Mbbls) (Mbbls) 4,079 7,932 9,308 858 4,782 – 1,100 3,496 – 812 2,133 –	NGLs (Mbbls) 1,424 215 173 17	Natural Shale Gas Gas Total
Aggregate Prior to 2007 2007 2008 2009			(Bcf) (Bcf) (MBOE) 227 – 60,577 24 – 9,865 14 – 7,036 4 5 4,427

Probable Undeveloped Reserves

Year(1)	Crude Oil Light & Heavy Medium Bitumen (Mbbls) (Mbbls) (Mbbls) 165 5,843 54,682 1,007 1,214 4,064 665 1,246 – 779 527 –	NGLs (Mbbls) 561 101 169 52	Natural Shale Gas Gas Total
Aggregate Prior to 2007 2007 2008 2009			(Bcf) (Bcf) (MBOE) 117 – 80,710 18 – 9,342 11 – 3,880 6 14 4,778

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

A decrease in future commodity prices relative to the forecasts described above under ‘‘ – Forecast Prices and Costs ’’ could have a negative impact on Enerplus’ reserves, and in particular on the development of Undeveloped Reserves, unless future development costs are also reduced. Other than the foregoing and the factors disclosed or described in the tables above, 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 – Risks Relating to Enerplus’ Business and Operations – Enerplus’ actual reserves and resources will vary from its reserve and resource estimates, and those variations could be material ’’.

PROVED AND PROBABLE RESERVES NOT ON PRODUCTION

Enerplus has approximately 7,276 MBOE of Proved plus Probable Reserves which are capable of production but which, as of December 31, 2009, were not on production. These reserves have generally been non-producing for periods ranging from a few months to more than five years. In general, these reserves are related to commercially producible volumes that are 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.

42 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Supplemental Operational Information

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 operates. Enerplus actively participates in industry-recognized programs at the highest possible levels in an effort to support continuous improvement.

Health and Safety

Enerplus’ 2009 safety performance improved compared to 2008 but was slightly below the average when compared to the Canadian Association of Petroleum Producers (‘‘ CAPP ’’) industry average. In 2009, Enerplus had an employee recordable injury frequency rate of 0.38 injuries per 200,000 man hours compared to 0.42 injuries per 200,000 man hours in 2008. Enerplus’ contractor total recordable injury frequency increased from 1.01 injuries per 200,000 man hours in 2008 to a rate of 1.10 injuries in 2009. While the majority of incidents were of a lower severity, Enerplus endeavours to be proactive in the prevention of all incidents.

Health, safety and environmental (‘‘ HSE ’’) risks influence workplace practices, operating costs and the establishment of regulatory standards. Enerplus maintains a comprehensive HSE management system designed to:

• increase emphasis on safety awareness and to promote continuous improvement and safety excellence;

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

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

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

Enerplus continues to research, develop and implement proactive prevention measures and safety management program improvements that are designed to support its focus and commitment for an injury-free workplace. Enerplus management maintains its commitment towards improved health and safety performance by supporting a culture in which all employees and contractors embrace safety in their day-to-day activities.

Environment

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

• Enerplus participates in the CAPP Stewardship Program at the highest level (platinum). Enerplus’ participation in this program 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;

• Reclamation and site abandonment expenditures for 2009 totalled $10.9 million, up $0.6 million from 2008 expenditures, as Enerplus continued with its abandonment commitments. In 2009 Enerplus also received its largest ever number of reclamation certificates as Alberta Environment confirmed that it had returned 107 sites to their original state. Site restoration occurs when areas are returned to their original state once operations have been completed;

• In 2009, Enerplus experienced an increase in pipeline failures with 50 such failures in 2009 versus 45 in 2008. The increase was a function of a full year of operations with the additional pipeline length acquired under the Focus acquisition, continued internal corrosion of an aging infrastructure in spite of increased resources applied to corrosion inhibition, and non-metallic pipe physical failures. To reduce this failure rate, Enerplus implemented the following in 2009: a new asset integrity software program to be fully implemented by year end 2010 that is designed to identify potential failure sites; new construction standards adopted for fibreglass pipe; and new procedures implemented for both operating and suspended steel pipelines;

• Enerplus has a site inspection program and a corrosion risk management program designed to ensure compliance with HSE legislation and regulations. In 2009, Enerplus expanded its internal field inspections program to include inspections for compliance with all regulatory requirements at 148 major facilities; and

• Enerplus normally calculates its greenhouse gas emissions for the prior calendar year in the first and second quarter of the current year, to meet the CAPP Stewardship Program reporting schedule. Therefore, results for 2009 are not yet available. Enerplus is currently working

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 43

with a third party consultant to select a measurement and calculation protocol to be used in validating both its baseline greenhouse gas emissions and any on-going reductions made in its emissions. Enerplus intends to select a protocol that will meet the ultimate requirements of the Canadian and U.S. governments. In the interim, Enerplus has estimated its greenhouse gas emissions using the CAPP methodology. For 2008, Enerplus has estimated its direct and indirect emissions to be approximately 676,000 CO2 equivalent tonnes per year, and 246,000 CO2 equivalent tonnes per year, respectively. The future adopted validation protocol, with direction from the Canadian and U.S. federal governments, may result in a change in these estimates. In 2009 Enerplus completed a fugitive emissions camera survey on 123 facilities across the four western provinces, and is working to repair identified leaks.

Enerplus endeavours to carry out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice. 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 of the board of directors of EnerMark. At present, Enerplus believes that it is, and intends to continue to be, in compliance with all material applicable environmental laws 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 6% of the total development expenditures incurred by Enerplus in 2009. Specific greenhouse gas regulations have been enacted in Alberta and British Columbia. In Alberta, while Enerplus does not operate facilities that qualify as large emitters, Enerplus is required to pay its share of the costs at non-operated large emitter facilities, and in 2009 this cost was approximately $150,000. In British Columbia, Enerplus is subject to the carbon tax introduced in mid-2008. The cost of this tax was $0.64 million in 2009. Until there is more certainty with respect to the federal greenhouse gas regulations, Enerplus is unable to estimate the future potential costs in this area, although at this time Enerplus does not expect such costs to be material at its current hydrocarbon production levels and at the current price of carbon offsets in the marketplace of approximately $15 per tonne of CO2 equivalent. In the U.S., the federal Environmental Protection Agency has issued regulations limiting CO2 emissions from heavy industrial plants. Phase-in of these regulations has been deferred until 2011, and Enerplus does not expect these to affect its business at this time. Enerplus intends to continue to improve its energy efficiency regardless of the ultimate regulations. See ‘‘ Industry Conditions – Environmental Regulation ’’ and ‘‘ Risk Factors ’’.

Overall, Enerplus believes its HSE 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 and appropriate coverage, together with 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, 2009, Enerplus employed a total of 779 persons, including full-time benefit and payroll consultants.

44 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Information Respecting Enerplus Resources Fund

DESCRIPTION OF THE TRUST UNITS AND THE TRUST INDENTURE

The following is a summary of certain provisions of the Trust Indenture and the Trust Units. For a complete description, reference should be made to the Trust Indenture, a copy of which may be viewed at the offices of, or obtained from, the Trustee. A copy of the Trust Indenture was filed on the Fund’s SEDAR profile at www.sedar.com on May 30, 2008 and on EDGAR at www.sec.gov on June 11, 2008.

General

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

Trust Units and Other Securities of the Fund

The Fund is authorized to issue an unlimited number of Trust Units and 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 EELP Exchangeable LP Units assumed by Enerplus in connection with its acquisition of Focus, see ‘‘ Appendix G – Information Regarding Enerplus Exchangeable Limited Partnership ’’.

The Trustee

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

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

The Trustee shall be removed by notice in writing delivered by EnerMark to the Trustee if the Trustee fails to meet certain criteria stated within the Trust Indenture or with the approval of at least 66[2] ⁄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

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 45

appointment by a successor trustee. If the Trustee is removed by EnerMark, EnerMark may appoint a successor trustee. If the Trustee resigns or is removed by unitholders, its successor must be either appointed by EnerMark or the unitholders. If a successor trustee does not accept its appointment as trustee, a court may appoint the successor trustee.

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

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

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

Responsibilities of and Delegation to EnerMark

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

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

46 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Certain Restrictions on Powers of the Trustee and EnerMark

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

• (i) amend the Trust Indenture (except in certain circumstances described under ‘‘ – Amendments to the Trust Indenture ’’ below);

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

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

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

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

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

Non-Resident Ownership Provisions

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 ’’, 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 ’’.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 47

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.

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 EELP Exchangeable LP Units, see ‘‘ Appendix G – Information Regarding Enerplus Exchangeable Limited Partnership ’’.

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.

48 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

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

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

Redemption Right

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

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

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

The price that unitholders receive for Trust Units surrendered for redemption during any calendar month will be paid to the unitholder on the last day of the following month. However, there is 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, tax free savings accounts 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 49

Term and Termination of the Fund

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

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

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

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. The current auditors of the Fund are Deloitte & Touche LLP, Independent Registered Chartered Accountants.

Amendments to the Trust Indenture

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

• (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’’ 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;

50 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

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

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

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

DESCRIPTION OF THE ROYALTY AGREEMENTS AND 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.

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,

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 51

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 12, 2010. Enerplus fully complies with the provisions of National Instrument 58-101 – Disclosure of Corporate Governance Practices, National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings and National 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 adopted a Unitholder Rights Plan Agreement (the ‘‘ Rights Plan ’’), 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, 2005 and 2008 annual general and special meetings of unitholders. The Rights Plan must next be renewed and approved by the Fund’s unitholders at the annual general and special meeting to be held in 2011. The Rights Plan, under which Computershare Trust Company of Canada acts as rights agent, generally provides that, following the acquisition by any person or entity of 20% or more of the issued and outstanding Trust Units (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Trust Units, other than such acquiring person or entity, shall be entitled to acquire Trust Units at a discounted price. The Rights Plan is similar to other shareholder or unitholder rights plans adopted in the energy sector. A copy of the Rights Plan was filed as a ‘‘Security holder document’’ on May 12, 2008 on the Fund’s SEDAR profile at www.sedar.com, was filed on EDGAR at www.sec.gov on May 13, 2008, and is available on the Fund’s website at www.enerplus.com under ‘‘Corporate Governance’’.

52 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Debt of Enerplus

The Fund or its subsidiaries may, with the approval of the board of directors of EnerMark, borrow, incur indebtedness, give any guarantee or enter into any subordination agreement, or pledge or provide any security interest or encumbrance on any property of the Fund or its subsidiaries. At present, all third party indebtedness of Enerplus is incurred directly by its primary Operating Subsidiary, EnerMark. As at December 31, 2009, EnerMark had senior debt facilities comprised of a $1.4 billion bank credit facility (the ‘‘ Bank Credit Facility ’’) and US$494 million principal amount and $40 million principal amount of senior unsecured notes (collectively, 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 Note Purchase Agreement for each of the first two 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. A form of the Note Purchase Agreement for each of the most recent three series of Senior Unsecured Notes was filed on June 23, 2009 on the Fund’s SEDAR profile and on June 25, 2009 on EDGAR.

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, 2009, the entire facility was undrawn and Enerplus was in compliance with the covenants described below. 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%.

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

Consolidated EBITDA:	The aggregate of the last four quarters’:
	• net income;
	• interest expense;
	• all provisions for federal, provincial or other income and capital taxes;
	• depletion, depreciation, amortization and accretion; and
	• other non-cash amounts.
Consolidated Senior Debt:	All indebtedness and obligations in respect of amounts borrowed excluding Subordinated Debt.
Consolidated Total Debt:	The aggregate of Consolidated Senior Debt and Subordinated Debt.
Material Acquisition:	An acquisition or series of acquisitions which increases the tangible assets of Enerplus by more
	than 5%.
Subordinated Debt:	Debt which, by its terms, is subordinated to the Bank Credit Facility (but excludes convertible
	debentures which allow the Fund to issue Trust Units or other securities of the Fund in satisfaction of
	interest or principal).
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 Senior Unsecured Notes which total US$494 million and $40 million through issuances of (i) US$175 million on June 19, 2002, (ii) US$54 million on October 1, 2003, and (iii) US$225 million, US$40 million and $40 million on June 18, 2009, as summarized below:

		Coupon	Interest
Issue Date	Principal	Rate	Payment Dates	Maturity Date	Term
June 18, 2009	$40 million	6.37%	June 18 and December 18	June 18, 2015	Bullet payment on maturity
June 18, 2009	US$40 million	6.82%	June 18 and December 18	June 18, 2015	Bullet payment on maturity
June 18, 2009	US$225 million	7.97%	June 18 and December 18	June 18, 2021	Principal payments required in 5 equal
					instalments beginning June 18, 2017
October 1, 2003	US$54 million	5.46%	April 1 and October 1	October 1, 2015	Principal payments required in 5 equal
					instalments beginning October 1, 2011
June 19, 2002	US$175 million	6.62%	June 19 and December 19	June 19, 2014	Principal payments required in 5 equal
					instalments beginning June 19, 2010

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

54 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

entered into foreign exchange swaps that effectively fix the five principal payments on the US$54 million notes at an aggregate notional amount of $55.1 million.

Additional information regarding EnerMark’s debt arrangements is contained in Note 6 to the Fund’s audited annual consolidated financial statements for the year ended December 31, 2009 and under the heading ‘‘Liquidity and Capital Resources’’ in Enerplus’ management’s discussion and analysis for the year ended December 31, 2009. 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 and are subject to foreign exchange rate risk on such payments.

As of December 31, 2009 Enerplus also had outstanding a total of approximately 6,382,000 EELP Exchangeable LP Units, each of which is exchangeable, for no additional consideration, into 0.425 of a Trust Unit (for an aggregate of approximately 2,712,000 Trust Units). Accordingly, each EELP 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 Enerplus Exchangeable Limited Partnership ’’.

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 EELP Exchangeable LP Units. For the year ended December 31, 2009, approximately 47% of the Fund’s cash flow from operating activities was paid in cash distributions to unitholders.

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 2006:

Month of Record and Payment Date		2010		2009		2008		2007		2006
January(1)	$	0.18	$	0.25	$	0.42	$	0.42	$	0.42
February		0.18		0.18		0.42		0.42		0.42
March		0.18		0.18		0.42		0.42		0.42
April		N/A		0.18		0.42		0.42		0.42
May		N/A		0.18		0.42		0.42		0.42
June		N/A		0.18		0.42		0.42		0.42
July		N/A		0.18		0.42		0.42		0.42
August		N/A		0.18		0.42		0.42		0.42
September		N/A		0.18		0.47		0.42		0.42
October		N/A		0.18		0.47		0.42		0.42
November		N/A		0.18		0.38		0.42		0.42
December		N/A		0.18		0.38		0.42		0.42

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: ‘‘ Low or volatile 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 ’’; ‘‘ 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 unitholde rs’’ 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 2009 distributions was a return of capital and approximately 98% was taxable to unitholders as other income.

U.S. TAX REPORTING MATTERS

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

Based upon the computation of current and accumulated earnings and profit in accordance with U.S. federal income tax principles, approximately 86% of the distributions paid by the Fund during 2009 were considered to be dividends, with the remaining 14% considered a return of capital which should reduce the unitholder’s adjusted cost base for its Trust Units. Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 (P.L. 108-27, 117 Stat. 752), the dividend portion of Enerplus’ 2009 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 in its present form by the U.S. government at such time.

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, subject to certain limitations.

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U.S. unitholders should consult their own tax advisors with respect to distributions paid by the Fund, including with respect to the taxation of distributions, dividends or similar payments if the SIFT income tax provisions apply to the Fund beginning in 2011 or if the Fund converts to a corporation or other form of entity.

For additional information, 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 ’’.

58 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

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 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, Saskatchewan and British Columbia, which accounted for approximately 87% of Enerplus’ 2009 production). Enerplus also owns oil and natural gas properties and related assets in the province of Manitoba and in Montana, North Dakota, Pennsylvania, West Virginia, Maryland, Wyoming and Utah 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 rateability 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 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, 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

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from the NEB. Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

PRICING AND MARKETING – NATURAL GAS

The price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The price depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, seasonal factors, weather conditions, the value of refined products, 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 AMERICA FREE TRADE AGREEMENT (‘‘NAFTA’’)

On January 1, 1994, the North American Free Trade Agreement (‘‘ 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

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

From time to time, the federal and provincial governments in Canada have established incentive programs which have included royalty rate reductions (including for specific wells), royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects. If applicable, oil and natural gas royalty holidays, reductions and tax credits would effectively reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments.

In addition to federal regulations, each state in the U.S. has legislation and regulations which govern oil and gas land holdings, royalties, production rates, environmental protection and other matters. In all U.S. jurisdictions, producers of oil and natural gas are typically required to pay annual rental payments in respect of federal, state and freehold leases until production begins. Upon commencement of production,

60 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

royalties and production taxes are paid in respect of oil and natural gas produced from federal, state and freehold lands. The royalty and production tax regime is a significant factor in the profitability of oil and natural gas production.

Royalties payable on production from lands other than federal and state lands are determined by negotiations between the freehold mineral owner and the lessee. Federal and state royalties and production taxes are determined by government regulation and are generally calculated as a percentage of the value of the gross production. Other royalties and royalty-like interests are from time to time carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties or net profits or net carried interests.

From time to time, the federal and state governments in the U.S. have established incentive programs which have included royalty rate or production tax 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. If applicable, oil and natural gas royalty holidays, reductions and tax credits would effectively reduce the amount of federal and state royalties or taxes paid by oil and gas producers to the governmental entities.

LAND TENURE

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

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

Crude oil and natural gas located in the U.S. is predominantly owned by private owners. The Federal Government (Bureau of Land Management), Bureau of Indian Affairs and the state in which the minerals are located also may hold ownership to such rights. These owners, from governmental bodies to private individuals, grant rights to explore for and produce oil and gas pursuant to leases, licenses and permits for varying periods and on conditions including requirements to perform specific work or make payments. As to those rights held by private owners, all terms and conditions may be negotiated. For those rights held by governmental agencies, typically the terms and conditions of the oil and gas lease have been predetermined by each governing or regulatory body. The majority (approximately 80%) of all leaseholds currently owned by Enerplus in the U.S. have been granted through private individuals.

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 have been timely paid, subject to certain exceptions. In order to develop minerals, including oil and gas, it is necessary for the mineral estate owner to have access to the surface estate. Under common law, the mineral estate is considered the ‘‘dominant’’ estate with the right to extract minerals subject to reasonable use of the surface. Each state has developed and adopted their own statutes that operators must follow both prior to drilling and following drilling including notification requirements and to provide compensation for lost land use and surface damages. The surface rights required for pipelines and 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 federal, provincial and state 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 the applicable 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

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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, the 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 2008, the Government of British Columbia instituted a carbon tax that applies to all fuel users in the province.

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 continues to evaluate 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 Alberta provincial government has instituted 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, Enerplus believes that 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. Enerplus has complied with this requirement. It is believed this information will be used toward the forthcoming implementation plan. In 2008, the Province of British Columbia instituted a carbon tax and a ‘‘cap and trade’’ system for large emitters of greenhouse gases. See ‘‘ Supplemental Operational Information – Health, Safety and Environment – Environment ’’.

On March 10, 2008, the Canadian federal government proposed new regulations as part of its ‘‘Turning the Corner’’ plan that would require all facilities emitting more than 3,000 tonnes of carbon dioxide per year to reduce emissions over time, and oil sands projects starting operations in 2012 and beyond to reduce greenhouse gas emissions, largely through carbon capture technology. The potential impact on both conventional oil and gas and 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. Subsequent to the International Climate Change meeting in Copenhagen in December 2009, the United States and Canada committed to a 17% reduction in greenhouse gas emissions by 2020 relative to a 2005 baseline, but without further implementation details. The Canadian federal government continues to seek to align its greenhouse gas regulations with those of the United States, and therefore its regulations remain pending. In addition to Alberta, certain other Canadian provincial governments (e.g., British Columbia 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.

In the United States, environmental compliance is governed by federal regulations, specifically the Clean Air Act and the Clean Water Act . These regulations are administered by the U.S. Environmental Protection Agency (the ‘‘ EPA ’’) at the federal level, or by various states whose programs have been granted primacy by the EPA. Enerplus’ U.S. operations are currently subject to various regulations under respective oil and gas acts from the Montana Board of Oil and Gas and Department of Environmental Quality, the North Dakota Department of Heath and Oil & Gas Division, and the Utah Division of Oil, Gas, and Mining and the Division of Environmental Quality. Enerplus’ Marcellus shale gas operations are regulated by Pennsylvania’s Department of Environmental Quality and in West Virginia by the Department of Environmental Protection.

The American Clean Energy And Security Act of 2009 , which contains a national cap-and-trade system with respect to greenhouse gas emissions, has been passed by the U.S. Congress and is currently before the U.S. Senate. Among other things, the Act would require greenhouse gas emissions to be reduced 17% from 2005 levels by 2020 and 83% by 2050, and implement carbon emissions costs. There can be no assurance whether this legislation will be passed by the U.S. Senate in its current or an alternative form, or passed at all. In addition, the EPA announced on December 7, 2009 its findings that emissions of carbon dioxide, methane and other ‘‘greenhouse gases’’ present an endangerment to human health and the environment. These findings by the U.S. EPA may allow the agency to proceed with the

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adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act . The EPA has also issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, even when such production is not emitted to the atmosphere. The implementation of more stringent environmental regulations on Enerplus’ U.S. operations could adversely affect Enerplus’ results from its U.S. operations.

See ‘‘ Risk Factors – Risks Related to Enerplus’ Business and Operations – Enerplus’ operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities ’’ and ‘‘ Risk Factors – Risks Related to Enerplus’ Business and Operations – Government regulations and required regulatory approvals may adversely impact Enerplus’ operations and result in increased operating and capital costs ’’.

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

WORKER SAFETY

Oilfield operations must be carried out in accordance with safe work procedures, rules and policies contained in applicable 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. The legislation, which provides for accident reporting procedures, also requires that every employer ensure that all of its employees are aware of their duties and responsibilities under the applicable legislation. Penalties under applicable occupational health and safety legislation include significant fines and incarceration.

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Risk Factors

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. 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. 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. Each of these risks may negatively affect the trading price of the Fund’s Trust Units or the amount of distributions paid to unitholders.

In particular, Enerplus directs unitholders and prospective investors to the description of the risks under the headings ‘‘ Risk Factors – Risks Related to Enerplus’ Business and Operations – Enerplus’ proposed strategy, including its proposed increased focus on growth-oriented projects and acquisitions, may expose Enerplus’ operations to increased risks ’’ and ‘‘ Risk Factors – Risks Related to Enerplus’ Structure and the Ownership of the Trust Units ’’ as the implementation of the SIFT Tax and the potential conversion from a trust structure to a corporate structure may have a significant impact on Enerplus’ business, operations and financial condition, as well as the value of the Trust Units to unitholders. Readers should read the following risk factors understanding that Enerplus currently intends to convert from an income trust that pays cash distributions to a dividend paying corporation on or before January 1, 2011, which should be incorporated with the impact of accompanying changes to Enerplus’ strategy as outlined elsewhere in this Annual Information Form.

RISKS RELATED TO ENERPLUS’ BUSINESS AND OPERATIONS

Low or volatile 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;

• global and domestic economic conditions;

• the level of consumer demand;

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

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

• currency fluctuations;

• weather conditions;

• 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 and greenhouse gas reduction 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. Certain oil or natural gas wells may become or remain uneconomic to produce if commodity prices are low, thereby impacting Enerplus’ production volumes. Any resulting decline in Enerplus’ cash flow could reduce the market value of the Trust Units or distributions paid to the Fund’s unitholders.

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Enerplus’ proposed strategy, including its proposed increased focus on growth-oriented projects and acquisitions, may expose Enerplus’ operations to increased risks.

As described under ‘‘ General Development of the Fund ’’ and ‘‘ Business of Enerplus ’’, Enerplus is currently transitioning from an income model to a hybrid growth and income-oriented model in response to both the SIFT Tax anticipated to come into effect on January 1, 2011 and current industry conditions. This transition includes an increased emphasis on higher risk growth plays such as the Bakken/Tight Oil, Marcellus Shale Gas and Canadian Deep Basin Tight Gas resources plays, may expose Enerplus to additional risks in its business and operations than has historically been the case, and there can be no assurance that the transition will be made successfully and will not result in adverse financial or operational results to Enerplus. These types of resource plays are earlier stage development projects (and in certain cases are more exploration-oriented in nature) than Enerplus has historically participated in and, as a result, there is more risk that Enerplus’ expenditures on land, seismic and drilling may not provide economic returns. To the extent that Enerplus acquires properties or assets with a higher risk exploration profile, the risk associated with such acquisitions and future development of such properties carries similar risks. Additionally, Enerplus may face increased competition in its industry as other former income-oriented issuers transition to a more growthoriented corporate model.

See also ‘‘ Risk Factors – Risks Related to Enerplus’ Structure and the Ownership of the Trust Units ’’ for risks associated with the proposed conversion of Enerplus from an income trust to a corporation.

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 from those Operating Subsidiaries 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 debt or 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 current amount will continue to be available or will be adequate for the financial obligations of Enerplus or that additional funds can be obtained as required or on terms which are economically advantageous to Enerplus. 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.

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

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Trust Unit. Additionally, from time to time, Enerplus may issue Trust Units or other securities from treasury in order to reduce debt, complete acquisitions 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, unavailable or available on less favourable terms, 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 may be reduced.

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 renew its Bank Credit Facilities or obtain additional financing on attractive economic terms, if at all. Enerplus’ Bank Credit Facility is generally 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. As a result of high fees and borrowing costs associated with renewing Enerplus’ Bank Credit Facility in 2008 and 2009, Enerplus decided not to renew the facility at those times and as a result the Bank Credit Facility expires in November 2010. Although Enerplus expects to renew the Bank Credit Facility in the second quarter of 2010, there can be no assurance that such a renewal will be available on favourable terms or that all of the current lenders under the facility will renew at their current commitment levels. If this occurs, Enerplus may need to obtain alternate financing. Additionally, Enerplus must repay the first of five annual principal instalments of approximately $53.7 million on $268.3 million of Senior Unsecured Notes commencing June 19, 2010 and $11 million on $55.1 million of Senior Unsecured Notes commencing October 1, 2011. See ‘‘ Debt of Enerplus ’’. Any failure of a member of the lending syndicate to fund its obligations under the Credit Facilities or to renew its commitment in respect of such Credit Facilities, or failure of Enerplus 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.

Enerplus’ commodity risk management activities could expose it to losses.

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.

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, as occurred through the last half of 2009, 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. Enerplus currently has in place a cross-currency swap associated with the US$175 million of Senior Unsecured Notes issued by EnerMark in June 2002 and a foreign exchange swap that effectively fixes the principal payments on its US$54 million of Senior Unsecured Notes issued in October 2003, each as described in Notes 6(b), 8 and 11 to the Fund’s audited consolidated financial statements for the year ended December 31, 2009. Also see ‘‘ Debt of Enerplus – Senior Unsecured Notes ’’.

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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 its existing 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. Additionally, if capital from external sources is not available or is not available on commercially advantageous 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 that it will be successful in acquiring additional reserves or resources on terms that meet its investment objectives. Without these additions, Enerplus’ reserves will deplete and, as a consequence, either its production or the average life of its reserves will decline. Either decline may result in a reduction in the value of the Trust Units and in a reduction in cash distributions to the Fund’s unitholders.

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

The value of the Trust Units depends upon, among other things, the reserves and resources attributable to Enerplus’ properties. The actual reserves and resources contained in Enerplus’ properties will vary from the estimates summarized in this 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.

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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 may impair the economic viability of certain reserves or resources in any particular period. With respect to Enerplus’ oil sands assets, no assurance can be provided as to the gravity or quality of bitumen produced from Enerplus’ Kirby oil sands project, and the volume and estimated value of the reserves or resources attributed to the project may vary.

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 ‘‘ Business of Enerplus – Enerplus’ Resource Play Types ’’.

Enerplus may not realize the anticipated benefits of its acquisitions or dispositions.

From time to time, Enerplus may acquire additional oil and natural gas properties and related assets. 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, capital and other resources from other strategic opportunities and 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.

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.

Furthermore, potential investors should be aware that certain acquisitions, and in particular acquisitions of oil sands assets such as Kirby in 2007 and of shale gas assets such as the Marcellus Properties in 2009 or other higher risk/higher growth assets, 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 or may receive cash flow in an amount less than anticipated. 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’ right to maintain the working interests acquired in the Marcellus Properties pursuant to the Marcellus JDA is subject to Enerplus fulfilling certain contractual requirements under the Marcellus JDA, including certain ongoing financial commitments which, if not fulfilled, could result in the forfeiture of certain of such interests as well as rights under the AMI Agreements. See ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Acquisition of Interests in the Marcellus Properties ’’ and ‘‘ Business of Enerplus – Enerplus’ Resource Play Types – Marcellus Shale Gas’’ . While Enerplus intends to fulfill, and expects to have sufficient financial resources to fulfill, its obligations pursuant to the Marcellus JDA, no assurance can be given that Enerplus will be able to fulfill these commitments as required and maintain its working interests.

Enerplus may also from time to time dispose of properties and assets, including its proposed disposition of significant non-core properties in 2010 as described under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Additional Strategic Acquisitions and Dispositions ’’. 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 be successful in such dispositions or 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 Enerplus’ results of operations or 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

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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. To the extent that Enerplus makes acquisitions with higher growth potential, the higher risks often associated with such potential may result in increased chances that actual results may vary from Enerplus’ initial estimates.

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.

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.

Higher operating costs for Enerplus’ properties will directly decrease the amount of cash flow received by the Fund. 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. Higher operation costs or a significant decline in production could result in materially lower cash flow and, therefore, could adversely affect the trading price of the Trust Units and reduce the amount available for distributions to unitholders.

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. Approximately 29% of Enerplus’ daily production is from properties operated by third parties. This results in significant reliance on third party operators in making estimates of future capital expenditures. To the extent a third party operator fails to perform these duties properly, faces capital or liquidity constraints or becomes insolvent, Enerplus’ results of operations will be negatively impacted and its cash flow may be reduced.

In particular, Enerplus will be heavily reliant on Chief and its other working interest partners in the development of, and operations on, the Marcellus Properties. Chief will generally be the operator of the Marcellus Properties in which Enerplus has acquired an interest, and accordingly, Enerplus will not exercise the degree of control over the operation and development of its Marcellus interests as it would if it were the operator. Additionally, under the terms of the Marcellus JDA, until such time as Enerplus has fully expended the full Marcellus Carry Amount, Chief will exercise significant control over where, when and in what amounts the Enerplus-funded capital is to be expended. The timing and amount of capital required to be spent by Enerplus may differ from Enerplus’ expectations and planning, and may impact the ability and/or cost of Enerplus to finance such expenditures, as well as adversely affect other parts of Enerplus’ business and operations. Furthermore, although Enerplus has entered into an agreement with an affiliate of Chief to gather and process Enerplus’ gas production from the Marcellus Properties, Enerplus does not own or operate any midstream or transportation assets in the Marcellus region and will rely on industry partners, including Chief, for such services.

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

Enerplus is subject to risk of default by the counterparties to Enerplus’ contracts.

Enerplus is subject to the risk that the counterparties to its risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements, including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad debts related to Enerplus’ joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to Enerplus may adversely affect the results of operations, cash flows and financial position of Enerplus.

Delays in payment for 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 Enerplus or 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:

• capital or liquidity constraints experienced by such parties, including restrictions imposed by lenders;

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• 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.

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, rank ahead of payments of cash from the Operating Subsidiaries to the Fund and therefore reduce 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 US$494 million and $40 million of Senior Unsecured Notes outstanding. Variations in interest rates and scheduled principal repayments could result in significant changes to the amount of the cash flow 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’ operations are subject to certain risks and liabilities inherent in the oil and natural gas business, some of which may not be covered by insurance.

Enerplus’ business and operations, including the drilling of oil and natural gas wells and the production and transportation of oil and natural gas, are subject to certain risks inherent in the oil and natural gas business. These risks and hazards include encountering unexpected formations or pressures, blow-outs, craterings and fires. Enerplus’ operations may also subject it to the risk of vandalism or terrorist threats, including eco-terrorism. The foregoing hazards could result in personal injury, loss of life, reduced production volumes 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. Although Enerplus carries liability, business interruption and property insurance in respect of such matters, 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. 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 Kirby properties acquired by Enerplus in 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, it may have an adverse effect on the 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 Enerplus 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.

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The Marcellus Shale Gas resource play involves certain additional risks and uncertainties. The drilling and completion of wells and operations in shale gas plays, and in particular the Marcellus shale region, present certain challenges that differ from conventional oil and gas operations. Wells in the Marcellus shale area generally must be drilled deeper than in many other areas, which makes the Marcellus shale wells more expensive to drill and complete. The wells may also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. In addition, the fracturing of the Marcellus shale may be more extensive and complicated than fracturing the geological formations in Enerplus’ other areas of operation and requires greater volumes of water than conventional gas wells. The management of water and the treatment of produced water from Marcellus shale wells may be more costly than the management of produced water from other geologic formations.

For additional information relating to certain litigation surrounding Enerplus’ Marcellus Properties, see ‘‘ – Unforseen title defects or litigation may result in a loss of entitlement to production, reserves and resources ’’ below.

Unforeseen title defects or litigation may result in a loss of entitlement to production, 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.

In particular, a significant amount of the lands that Enerplus has acquired pursuant to the Marcellus Acquisition is located in the state of Pennsylvania. Pennsylvania and West Virginia (and possibly other states) have legislation requiring the lessee of a freehold oil and gas lease to provide the lessor with a minimum royalty equal to one-eighth of the hydrocarbons produced from the leased lands. Any oil and gas lease which does not provide for this minimum royalty will be deemed invalid pursuant to this legislation. Currently, there are several ongoing legal actions which have called into question the validity of existing oil and gas leases because, in calculating the royalty amount, they provide for the deduction of post-production costs that relate to the gathering, processing and marketing of the lessor’s share of the produced hydrocarbons from the leased lands. Certain plaintiffs in these lawsuits have suggested that, by virtue of the leases allowing these costs to be deducted from the lessor’s royalty, the lessor receives less than one-eighth of the production of hydrocarbons from the leased lands on a net basis and, as such, these provisions invalidate the lease. Although the Marcellus Vendors have advised Enerplus that they have taken certain steps to mitigate this risk (and in particular to enter into lease amendments with respect to developed properties), most or all of the leases acquired by Enerplus pursuant to the Marcellus Acquisition (and in particular, those relating to undeveloped lands) provide for the deduction of post-production costs from the lessor’s royalty share of production. The Marcellus Purchase Agreement and the Marcellus JDA provide that Enerplus will not be indemnified by the Marcellus Vendors with respect to the potential invalidity of the leases forming part of the Marcellus Properties as a result of such litigation. The Pennsylvania Supreme Court heard a case in September 2009 regarding the minimum royalty provisions ( Kilmer v. Elexco Land Servs., Inc., No. 63 MAP 2009 (Pa.)) but as of the date of this Annual Information Form has not yet issued a ruling. There is no assurance that the Pennsylvania Supreme Court or other courts hearing these matters will rule in favour of validating these leases and it is possible that an adverse ruling could deprive Enerplus of some or all of the economic benefit of the leases it acquired in the Marcellus Acquisition.

As a result of Enerplus’ acquisition in the Marcellus Properties, or 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.

Prior to 2009, Enerplus’ operations and expertise were historically focused on conventional oil and natural gas production and development in the Western Canadian Sedimentary Basin, the Williston Basin and the northwest and central United States, together with its participation in the development of oil sands reserves and resources in northern Alberta. The acquisition of the Marcellus Properties in the northeast United States in September 2009 represents a new focus by Enerplus on shale gas outside its traditional geographic areas. Although Enerplus will (and in particular, initially) rely significantly upon its partners, and particularly Chief, with respect to ongoing development, operations and certain future expansions in the Marcellus shale gas region, Enerplus has very limited experience in the drilling and development of shale gas properties, and in particular the Marcellus shale gas region. The expansion of Enerplus’ activities into this new resource play and location

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may present challenges and risks that Enerplus has not faced in the past, including operational and additional regulatory matters. Enerplus’ failure to manage these challenges and risks successfully may adversely affect results of operations and financial condition.

In the future, Enerplus may acquire oil and natural gas properties and assets outside these geographic areas. In addition, Enerplus’ activities are not limited to oil and natural gas production and development, and Enerplus could acquire other energy related assets. 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.

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 to provide access to markets for its production. 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. New resource plays generally experience a sharp increase in the amount of production being produced in the area which could exceed the existing capacity of the various gathering, processing and pipeline infrastructure. For example, pipeline and transportation constraints experienced by oil producers in Montana, North Dakota and southeast Saskatchewan became more pronounced in 2008 as a result of strong crude oil prices experienced in the first three quarters of the year and the corresponding increased drilling and development activities in these regions. Additionally, if and as exploration and drilling in the Marcellus shale gas play increases, the amount of natural gas and associated NGLs being produced by Enerplus and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If these constraints remain unresolved, Enerplus’ ability to transport its production in these regions may be impaired and could adversely impact Enerplus’ production volumes or realized prices from these areas.

While the third party pipelines generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of pipeline capacity, and unfavourable economic conditions or financing terms may defer or prevent the completion of certain pipeline projects or gathering systems that are planned for such areas. There are also occasionally operational reasons for curtailing transportation capacity. Accordingly, there can be periods where transportation capacity is insufficient to accommodate all of the production from a given region, causing added expense and/or volume curtailments for all shippers. In such event, Enerplus may have to defer development of or shut in its wells awaiting a pipeline connection or capacity and/or sell its production at lower prices than it would otherwise realize or than Enerplus currently projects, which would adversely affect Enerplus’ results of and cash flow from operations.

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, the Fund will, subject to its level of then-available tax pools, 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). As a result, Enerplus currently anticipates converting from a trust to a corporation on or before January 1, 2011: see ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus’ Strategy Post-2010 ’’. When Enerplus is effectively taxed as a corporation beginning for the 2011 year, either as a result of a conversion to a corporation or due to the effect of the SIFT Tax on Enerplus as a trust, Enerplus may be 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.

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

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, such as legislation that would require significant reductions in greenhouse gas emissions. See ‘‘ Industry Conditions – Environmental Regulation ’’ for a summary of certain proposals. Although the actual form such legislation or regulation may take is largely 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, and such costs may be significant.

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.

Changes in tax and other laws may adversely affect unitholders.

Income tax laws, such as the looming effectiveness of the SIFT Tax on January 1, 2011 or other tax laws that may affect the treatment of mutual fund trusts or the taxation of the Fund’s distributions to unitholders, or other laws or government incentive programs relating to the oil and gas industry, may be changed or interpreted in a manner that adversely affects the Fund and its unitholders. Additionally, tax authorities having jurisdiction over Enerplus (whether as a result of Enerplus’ operations or financing structures) or its securityholders may change or interpret applicable tax laws or treaties or administrative positions in a manner which is detrimental to Enerplus or its securityholders, or may disagree with how Enerplus calculates its income for tax purposes.

Government regulations and required regulatory approvals may adversely impact Enerplus’ operations and result in increased operating and capital costs.

The oil and gas industry operates under federal, provincial, state and municipal legislation and regulation governing such matters as royalties, land tenure, prices, production rates, environmental protection controls, well and facility design and operation, 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 Lease and Kirby Project), the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production), and possibly expropriation or cancellation of contract rights. See ‘‘ Industry Conditions ’’. To the extent that Enerplus fails to comply with applicable government regulations or regulatory approvals, Enerplus may be subject to fines, enforcement proceedings (including ‘‘enforcement ladders’’ with varying penalties) and the restriction or complete revocation of rights to conduct its business, or to apply for regulatory approvals necessary to conduct its business, in the ordinary course.

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 passed into law, effective January 1, 2009, significant revisions to the royalty regime in place in Alberta, which has since been supplemented by various incentive and royalty credit provisions. Alberta’s ‘‘New Royalty Framework’’ is sensitive to commodity price and production levels and any adverse impact on Enerplus will be particularly felt in periods of mid-level to high commodity prices.

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Additionally, various levels of Canadian and United States governments are considering legislation to reduce emissions of greenhouse gases. See ‘‘ Industry Conditions – Environmental Legislation ’’ for a description of certain of these initiatives. Because Enerplus’ operations emit various types of greenhouse gases, such new legislation or regulation could increase the costs related to operating and maintaining Enerplus’ facilities and could require it to install new emission controls on its facilities, acquire allowances for its greenhouse gas emissions, pay taxes related to its greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Enerplus is not able at this time to estimate such increased costs; however, they could be significant. Any of the foregoing could have adverse effects on Enerplus’ business, financial position, results of operations and prospects.

The U.S. government has proposed certain tax changes which may increase the amount and/or accelerate the timing of U.S. cash income taxes payable by entities with oil and gas operations in the U.S., including Enerplus. Among other potential changes, the U.S. administration is proposing to: repeal the current immediate 100% deduction for intangible drilling costs such that they would instead be deductible on a unit of production basis; increase the amortization period for certain geological and geophysical costs from two years to seven years; and repeal certain domestic manufacturing deductions for oil and gas production. Such proposed changes have not yet been included in a bill presented to the U.S. Congress or U.S. Senate, and accordingly Enerplus is unable to determine if or when these proposed tax changes would be enacted, or if enacted, whether such changes would be in the form presented or in a modified form. Furthermore, while Pennsylvania has historically not imposed a severance tax, with a focus on its budget deficit and the increasing exploitation of the Marcellus shale play, Pennsylvania’s governor recently proposed a tax of 5% of the value of natural gas at the wellhead plus $0.047 per Mcf. Although Enerplus assumed the implementation of such severance taxes in its evaluation of the Marcellus Acquisition, if adopted (or if adopted in an alternative form), these taxes may reduce the cash flow realized from Enerplus’ operations in Pennsylvania.

The development of the Kirby oil sands project is subject to numerous risks.

Enerplus has currently deferred the development of the Kirby Project and continues to evaluate its options to maximize the value of the Kirby Lease. Enerplus’ development of the Kirby Project may not proceed at all, and if it does proceed, there is a risk that the project, including any future phases or expansions, will not be completed as planned, on time or on budget. The development of the Kirby Lease may require significant financing, which may not be available or may only be available on unfavourable terms. Additionally, if the Kirby Project does proceed, there is a risk that the Kirby Project may have delays in development or commercial start-up, interruption of operations or increased costs due to many factors, including, without limitation:

• the economic viability of the Kirby Project or certain portions thereof;

• 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 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.

The information contained in this Annual Information Form regarding the Kirby Project (including, without limitation, current resource evaluations) and the development of such project is conditional upon an improvement in the current economics of the project, receipt of all regulatory approvals, the capital requirements of the project and Enerplus’ other projects, and certain economic factors.

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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, there can be no assurance that SAGD utilization on 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.

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.

Enerplus’ future adoption of International Financial Reporting Standards may adversely impact the Fund’s reported financial results.

The requirement for Enerplus to implement International Financial Reporting Standards (‘‘ IFRS ’’) to replace Canadian GAAP effective January 1, 2011 may materially affect the Fund’s financial results as reported in its financial statements and its results of operations and may require Enerplus to amend its Credit Facilities to address the changes in accounting principles. Enerplus is in the process of transitioning to IFRS and has completed its diagnostic phase assessing the differences between Canadian GAAP and IFRS but at this time Enerplus is unable to quantify the impact IFRS will have on its financial statements. For additional information, see ‘‘Future Accounting Changes’’ in the Fund’s management’s discussion and analysis for the year ended December 31, 2009.

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 is subject to a cost-recovery or ‘‘ceiling’’ test, which is based on future prices and estimated future pre-tax net revenue from Proved Reserves, calculated on an undiscounted basis. If the net capitalized costs exceed the estimated ‘‘recoverable amounts’’, a second test is performed. The second test is based on future prices and estimated future pre-tax net revenue from Proved plus Probable Reserves discounted at the risk-free rate. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

Under U.S. GAAP, the net capitalized cost of oil and gas properties, 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 the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer’s fiscal year-end. The amount by which the net capitalized costs exceed the discounted value will be charged to net income. Generally speaking, and particularly in a low commodity price environment, the use of the trailing twelve month average prices and discounting results in a greater likelihood of a ceiling test write-down under U.S. GAAP than Canadian GAAP.

A decline in oil and gas prices may result in the estimated ‘‘recoverable amounts’’ of Enerplus’ oil and natural gas properties to be less than the carrying value on the balance sheet, ultimately resulting in a charge against Enerplus’ earnings. While these write-downs would not affect cash flow, the charge to earnings may be viewed unfavourably in the market. At December 31, 2009, the application of the

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impairment test under U.S. GAAP resulted in a write down of $481.2 million ($363.4 million net of tax) of capitalized costs. There was no impairment of capitalized costs under Canadian GAAP.

In certain circumstances, Enerplus may be required under Canadian GAAP or U.S. GAAP to write down the value of the goodwill recorded on its balance sheet and incur a non-cash charge against its income.

Canadian and U.S. GAAP require that goodwill balances recorded on the balance sheet be assessed for impairment at least annually or more frequently if events or circumstances indicate that the balance might be impaired. The impairment assessment is subject to management estimates and assumptions and factors that may be considered include, but are not limited to, a decline in the Trust Unit price, a change in the fair value of Enerplus’ oil and natural gas reserves and other assets and liabilities, the current activity level in oil and natural gas property markets and general economic conditions. An impairment would result in a write-down of the goodwill value and a non-cash charge against net income. Enerplus’ goodwill balance was assessed for impairment as of December 31, 2009 and no impairment existed at that time.

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 loss of the services of key individuals could have a detrimental effect on the Fund.

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 – Conflicts of Interest ’’. No assurances can be given that opportunities identified by such persons will be provided to Enerplus.

RISKS RELATED TO ENERPLUS’ STRUCTURE AND THE OWNERSHIP OF THE TRUST UNITS

Distributions on the Fund’s Trust Units are variable.

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.

The actual cash flow available for distribution to the Fund’s 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; (v) foreign currency exchange rates and interest rates; and (vi) the risk factors set forth in this Annual Information Form. The amount of cash distributions is 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 expenditure 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 EELP Exchangeable LP Units. Distributions may be increased, reduced or suspended entirely depending on Enerplus’ operations and the performance of its assets. The market value of the Trust Units may deteriorate if the Fund is unable to meet distribution expectations in the future, and that deterioration may be material.

The application of the SIFT Tax in 2011 could adversely affect the Fund and its unitholders.

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 and Enerplus’ Strategy Post-2010 ’’. Enerplus expects that, if Enerplus continues in the form of an income trust after January 1, 2011 and does not convert to a corporation on or prior to such date as it currently anticipates, the implementation of the SIFT Tax will result in adverse tax consequences to Enerplus and certain

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unitholders (and in particular tax-exempt or tax-deferred Canadian residents and taxable non-residents of Canada) and may impact the level of cash distributions from the Fund to its unitholders. In particular:

• the Fund may be required to pay taxes, or higher amounts of taxes, in the future or in years earlier than it would under existing tax laws, which could decrease the ability of the Fund to pay monthly cash distributions or the amount of cash distributions available to its unitholders (see ‘‘ Business of Enerplus – Tax Horizon ’’ for a description of Enerplus’ tax position and certain assumptions related thereto);

• 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.

Additionally, as described under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus’ Strategy Post-2010 ’’, 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 certain significant acquisitions. While the Canadian federal government has accelerated the recognition of the safe harbour growth limits, 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.

As described under ‘‘ General Development of Enerplus Resources Fund – Developments in the Past Three Years – Changes to Taxation of Income Trusts and Enerplus’ Strategy Post-2010 ’’, Enerplus currently plans to convert from an income trust to a dividend paying corporation on or about January 1, 2011. Such a conversion must be approved by the board of directors of EnerMark as well as at least 66[2] ⁄3% of the Fund’s unitholders who vote at a special meeting to consider the conversion, which Enerplus anticipates will be held in December 2010. Although the SIFT Tax is expected to remove the benefits of remaining a trust, there is a risk that the Fund’s unitholders do not approve the conversion to a corporation or that other required conditions to such a conversion may not be satisfied, in which case Enerplus would remain as an income trust subject to the risks described above.

The conversion from an income trust to a corporation may have adverse effects on the Fund’s unitholders or the holders of EELP Exchangeable Units.

Enerplus does not currently anticipate that the conversion from an income trust to a corporation would create a taxable event for the Fund’s unitholders or the holders of EELP Exchangeable LP Units under Canadian or U.S. federal income tax laws. However, the final form, structure and steps involved in the conversion transaction have not yet been finalized and as a result Enerplus cannot guarantee that the conversion will not result in a taxable event for its securityholders. Furthermore, Enerplus has not undertaken a review of the income tax consequences of a conversion from a trust to a corporation in any jurisdiction other than Canada and the United States, and as a result there can be no assurance as to the income tax consequences of such a conversion to holder of Trust Units under income tax laws other than those of Canada and the United States, and such unitholders should consult their own tax advisors. Additionally, following a conversion to a corporation, the treatment of dividends that may be paid by the resultant corporation may be different for Enerplus’ securityholders depending on the nature of the holder, their jurisdiction of residence or taxation and whether the investment in Enerplus is held in a taxable or tax-deferred account.

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While Enerplus remains an income trust, there would be material adverse consequences if the Fund lost its status as a mutual fund trust under Canadian tax laws.

Enerplus currently anticipates that the Fund will continue to qualify as a mutual fund trust for purposes of the Tax Act until such time as it may convert to a corporation. However, the Fund may not always be able to satisfy any future requirements for the maintenance of 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 2010 an estimated 65% 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 until such time as it may convert to a corporation 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 prior to any conversion to a corporation. However, 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). 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 ’’.

Should the status of the Fund as a mutual fund trust be lost or successfully challenged by a relevant tax authority prior to Enerplus converting to a corporate form, 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;

• 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;

• if the Trust Units were not listed on a stock exchange that is a ‘‘designated stock exchange’’ for the purposes of the Tax Act (which currently includes the TSX and the NYSE), 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 ’’), tax free savings accounts (‘‘ TFSAs ’’) or deferred profit sharing plans (‘‘ DPSPs ’’). If, at the end of any month, one of these exempt plans (other than an RDSP or a TFSA) 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, RDSP or TFSA 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 or a TFSA 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; and

• 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

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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 or the right to dissent and be paid the ‘‘fair market value’’ of their securities in respect of certain significant transactions involving the Fund. 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). As a result, if a restructuring of the Fund was necessary, the Fund may not be able to access the remedies available thereunder, and, in the event of such a restructuring, the position of the Fund’s unitholders may be different than those of a Corporation. The unavailability of these statutory rights may also reduce the ability of the Fund’s unitholders to seek legal remedies against other parties on Enerplus’ behalf.

The Trust Units are 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 is 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 issuance of additional Trust Units in lieu of cash distributions could negatively affect the value of the Trust Units and result in the payment of taxes.

The Trust Indenture provides that an amount equal to the taxable income of the Fund will be payable each year to the Fund’s unitholders in order to reduce the Fund’s taxable income to zero. Where in a particular year, the Fund does not have sufficient cash to distribute such an amount, the Trust Indenture provides that additional Trust Units may be distributed to unitholders in lieu of cash payments. In such a case, unitholders will generally be required to include an amount equal to the fair market value of those Trust Units in their taxable income, notwithstanding that they do not directly receive a cash payment.

The redemption right 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.

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

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 79

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, both of which conditions are 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.

RISKS PARTICULAR TO UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS

In addition to the risk factors set forth above, 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 2008 taxable year and in subsequent taxable years. The Fund will be a PFIC if at least 75% of its income consists of dividends, interest, and other passive items or if 50% 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 2009, and Enerplus does not expect to be considered a PFIC for 2010.

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

80 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

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

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

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 ’’.

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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 81

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 United States composite trading information for 2009.

Month	TSX High Low Volume $28.00 $23.85 9,081,899 26.30 18.50 7,617,151 22.36 16.75 10,683,115 24.16 20.42 7,616,181 27.70 22.57 8,679,389 27.39 22.88 8,194,777 24.80 21.28 6,756,386 24.48 21.60 9,526,687 24.82 22.21 10,340,262 25.80 23.06 7,992,923 24.85 23.28 5,699,816 24.35 23.19 6,408,354	U.S. Composite Trading High Low Volume
January February March April May June July August September October November December		US$23.66 US$19.60 22,972,370 21.56 14.85 17,849,532 18.23 12.85 19,283,952 19.99 16.06 15,432,922 24.12 19.00 19,935,919 25.13 19.85 13,382,143 21.96 18.23 12,485,169 22.90 19.52 12,251,042 23.18 20.28 14,084,719 24.48 21.00 18,639,335 23.48 21.48 12,174,971 23.42 21.93 12,912,555

82 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Directors and Officers

DIRECTORS OF ENERMARK

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

Name and Residence	Director Since	Principal Occupation for Past Five Years
Edwin V. Dodge(4)(6)	May 2004	Corporate director.
Vancouver, British Columbia,
Canada
Robert B. Hodgins(2)(3)	November 2007	Independent businessman.
Calgary, Alberta, Canada
Gordon J. Kerr	May 2001	President and Chief Executive Officer of Enerplus.
Calgary, Alberta, Canada
Douglas R. Martin(1)(7)	September 2000	President of Charles Avenue Capital Corp. (a private merchant banking company).
Calgary, Alberta, Canada
David P. O’Brien(3)(8)	March 2008	Corporate director, including Chairman of EnCana Corporation (a TSX and NYSE-listed
Calgary, Alberta, Canada		oil and gas company) and Chairman of the Royal Bank of Canada (a TSX and
		NYSE-listed Canadian chartered bank).
Glen D. Roane(2)(4)	June 2004	Corporate director.
Canmore, Alberta, Canada
W.C. (Mike) Seth(3)(5)	August 2005	President of Seth Consultants Ltd. (a private consulting firm) since June 2006. From
Calgary, Alberta, Canada		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)	April 2003	Businessman.
Calgary, Alberta, Canada
Harry B. Wheeler(2)(5)	January 2001	President of Colchester Investments Ltd. (a private investment firm).
Calgary, Alberta, Canada
Clayton H. Woitas(5)(6)	March 2008	President of Range Royalty Management Ltd. (a private energy company) since
Calgary, Alberta, Canada		June 2006. Prior thereto, Chairman and Chief Executive Officer of Profico Energy
		Management Ltd. (a private oil and gas company).
Robert L. Zorich(3)(4)(9)	January 2001	Managing Director of EnCap Investments L.P. (a private firm that provides private equity
Houston, Texas, USA		financing to the oil and gas industry).

Notes:

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

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

(3) The Corporate Governance & Nominating Committee is comprised of Robert L. Zorich as Chairman, Robert B. Hodgins, David P. O’Brien and W.C. (Mike) Seth.

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

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

(6) The Health, Safety, Regulatory & Environment Committee is comprised of Edwin V. Dodge as Chairman, Donald T. West and Clayton H. Woitas.

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

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

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 83

OFFICERS OF ENERMARK

The name, municipality of residence, position held and principal occupation for the past five years for each officer of EnerMark as of March 12, 2010 are set out below.

Name and Residence	Office	Principal Occupation for Past Five Years
Gordon J. Kerr	President & Chief Executive	President & Chief Executive Officer of Enerplus.
Calgary, Alberta, Canada	Officer
Ian C. Dundas	Executive Vice President	Executive Vice President, Enerplus since March 2010. Prior thereto, Senior Vice
Calgary, Alberta, Canada		President, Business Development of Enerplus.
Robert J. Waters	Senior Vice President &	Senior Vice President & Chief Financial Officer of Enerplus.
Calgary, Alberta, Canada	Chief Financial Officer
Jo-Anne M. Caza	Vice President, Investor	Vice President, Investor Relations and Corporate Communications since January 2008.
Calgary, Alberta, Canada	Relations & Corporate	Prior thereto, Vice President, Investor Relations of Enerplus.
	Communications
Raymond J. Daniels	Vice President, Development	Vice President, Development Services & Oil Sands of Enerplus since July 2009. Prior
Calgary, Alberta, Canada	Services & Oil Sands	thereto, Vice President, Oil Sands of Enerplus since December 2007. Prior thereto, Vice
		President, Surmont Development, Surmont Opportunity Manager and Asset Manager,
		Central Region, each with ConocoPhillips Canada.
Rodney D. Gray	Vice President, Finance	Vice President, Finance of Enerplus.
Calgary, Alberta, Canada
Dana W. Johnson	President, U.S. Operations	President, U.S. Operations of Enerplus since May 2008. Prior thereto, Senior Vice
Denver, Colorado, U.S.A.		President and Chief Operating Officer of Quicksilver Resources Canada Inc., (a wholly-
		owned subsidiary of NYSE-listed Quicksilver Resources Inc., an oil and gas exploration
		and production company).
Lyonel G. Kawa	Vice President, Information	Vice President, Information Services since January 2007. Prior thereto, Manager,
Calgary, Alberta, Canada	Services	Information Systems and Technology with Burlington Resources Canada Ltd. (an oil and
		gas exploration and production company).
Robert A. Kehrig	Vice President, Resource	Vice President, Resource Development of Enerplus since October 2008. Prior thereto,
Calgary, Alberta, Canada	Development	Manager in Enerplus’ Business Development group.
Jennifer F. Koury	Vice President, Corporate	Vice President, Corporate Services of Enerplus since October 2006. Prior thereto, a
Calgary, Alberta, Canada	Services	private consultant.
Eric G. Le Dain	Vice President, Strategic	Vice President,Strategic Planning, Reserves & Marketing of Enerplus since March 2010.
Calgary, Alberta, Canada	Planning, Reserves &	Prior thereto, Vice President, Regulatory, Environment and Marketing of Enerplus since
	Marketing	December 2008. Prior thereto, 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	Vice President, General	Vice President, General Counsel & Corporate Secretary of Enerplus.
Calgary, Alberta, Canada	Counsel & Corporate
	Secretary
Robert W. Symonds	Vice President, Canadian	Vice President, Canadian Operations of Enerplus since March 2009. Prior thereto, Vice
Calgary, Alberta, Canada	Operations	President – Foothills & Corporate Development of Compton Petroleum Corporation (an
		oil and gas exploration and production company) since February 2008. Prior thereto,
		Vice President – Foothills Business Unit of Shell Canada Limited (an oil and gas
		company).
Kenneth W. Young	Vice President, Land	Vice President, Land of Enerplus since November 2008. Prior thereto, Vice President,
Calgary, Alberta, Canada		Land at Avant Garde Energy Corp. (a private oil and gas exploration and production
		company) since 2008. Prior thereto, independent consultant since 2007. Prior thereto,
		Vice President, Land of Zargon Oil & Gas Ltd. (a subsidiary of Zargon Energy Trust, an oil
		and gas income trust).
Jodine J. Jenson Labrie	Controller, Finance	Controller, Finance of Enerplus since March 2006. Prior thereto, Manager, Finance and
Calgary, Alberta, Canada		Senior Financial Accountant of Enerplus.

TRUST UNIT OWNERSHIP

As of February 24, 2010, the directors and officers named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 711,073 Trust Units, representing approximately 0.4% of the outstanding Trust Units as of that date, and 4,099,229 EELP

84 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Exchangeable LP Units, representing approximately 65% of the outstanding EELP Exchangeable LP Units as of that date. In the aggregate, such securities represent approximately 1.4% of the aggregate voting securities of the Fund.

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.

See ‘‘ Risk Factors – Conflicts of interest may arise between Enerplus and its directors and officers ’’.

AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE

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

Legal Proceedings and Regulatory Actions

Enerplus is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in Enerplus’ favour, Enerplus does not currently believe that the outcome of any pending or threatened proceedings related to these or other matters, or the amounts which Enerplus may be required to pay by reason thereof, would have a material adverse impact on its financial position, results of operation or liquidity. Enerplus is not and was not during 2009 a party to, and none of Enerplus’ property is or was during 2009 the subject of, any legal proceeding that involves a claim for damages (exclusive of interests and costs) greater than 10% of its current assets as at December 31, 2009, and Enerplus has no knowledge of any such proceeding being contemplated. However, as described under ‘‘ Risk Factors – Risks Relating to Enerplus’ Business and Operations – Unforeseen title defects or litigation may result in a loss of entitlement to production, reserves and resources ’’, most or all of the leases held by Enerplus on the Marcellus Properties may be adversely affected or invalidated as a result of certain litigation regarding the alleged improper calculation of minimum royalty payments owing to the lessors of such properties. It is possible that an adverse ruling with respect to these matters could deprive Enerplus of some or all of the potential economic benefit of the Marcellus Properties.

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 transaction with Enerplus since January 1, 2007 or in any proposed transaction that has materially affected or is reasonably expected to materially affect Enerplus.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 85

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 Note Purchase Agreement for each of the first two 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, and a form of Note Purchase Agreement for each of the three series of Senior Unsecured Notes issued on June 18, 2009 was filed on SEDAR on June 23, 2009 and on EDGAR on June 25, 2009.

A copy of the Trust Indenture, which is described under ‘‘ Information Respecting Enerplus Resources Fund – Description of the Trust Units and the Trust Indenture ’’, was filed on the Fund’s SEDAR profile at www.sedar.com on May 30, 2008 and on EDGAR at www.sec.gov on June 11, 2008. 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 May 12, 2008 and was filed on EDGAR at www.sec.gov on May 13, 2008, and is available on the Fund’s website at www.enerplus.com under ‘‘Corporate Governance’’.

Interests of Experts

McDaniel prepared the McDaniel 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 McDaniel Report, the ‘‘designated professionals’’ (as defined in Form 51-102F2 – Annual Information Form of the Canadian securities regulatory authorities) of McDaniel, 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. Haas prepared the Haas Report in respect of the reserves and contingent resources attributable to Enerplus’ interests in the Marcellus Properties, a summary of which is contained in this Annual Information Form. As of the date of the Haas Report, the designated professionals of Haas, as a group, beneficially owned, directly or indirectly, less than 1% of the Fund’s outstanding Trust Units. GLJ prepared the GLJ Oil Sands Resources Report in respect of the contingent and prospective bitumen resources attributable to the Kirby Lease (together with interests in certain minor non-operated oil sands projects), a summary of which is contained in this Annual Information Form. As of the date of 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.

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.

86 E N ER PL US R ES OURC ES 2009 ANNUAL INFORMATION FORM

Registrar and Transfer Agent

The registrar and transfer agent for the Trust Units in Canada is Computershare Trust Company of Canada, at its principal offices in Calgary, Alberta and Toronto, Ontario. Computershare Trust Company N.A. at its principal offices in Golden, Colorado is the 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 12, 2010 for its 2010 annual general meeting of unitholders. Furthermore, additional financial information relating to the Fund is provided in the Fund’s audited consolidated financial statements and management’s discussion and analysis for year ended December 31, 2009. 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 87

APPENDIX A

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, 2009. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009 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.

3. 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).

4. 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.

5. 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, 2009, and identifies the respective portions thereof that we have, evaluated, audited and reviewed and reported on to the Company’s management:

Preparation Date of Location of Evaluation Report Reserves	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate)
	Audited Evaluated Reviewed Total
Canada February 12, 2010	(in $ thousands) – $ 4,130,956 $ 477,326 $ 4,608,282

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

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

3. 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:

MCDANIEL & ASSOCIATES CONSULTANTS LIMITED

‘‘ P.A. Welch ’’

P.A. Welch, P. Eng. President & Managing Director Calgary, Alberta February 12, 2010

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM A-1

APPENDIX B

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 as at December 31, 2009. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009, 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.

3. 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).

4. 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.

5. 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, 2009, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:

Location of Description and Reserves (Country Independent Qualified Preparation Date of or Foreign Reserves Evaluator Evaluation Report Geographic Area)	Net Present Value of Future Net Revenue (before U.S. federal income taxes, 10% discount rate)
	Audited Evaluated Reviewed Total
Montana, North Netherland, Sewell & Estimate of Reserves and Dakota, Utah and Associates, Inc. Future Revenue to the Wyoming, USA Enerplus Resources (USA) Corporation Interest as of December 31, 2009, dated January 27, 2010	(US$ thousands) $ – $ 906,630.2 $ – $ 906,630.2

1. 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.

2. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

3. 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM B-1

Executed as to our report referred to above:

NETHERLAND, SEWELL & ASSOCIATES, INC. Dallas, Texas, USA February 23, 2010

/s/ G. LANCE BINDER

G. Lance Binder, P.E. Executive Vice President

B-2 E NE RP LU S RE SOUR C ES 2009 ANNUAL INFORMATION FORM

APPENDIX C

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, 2009. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009, 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).

1. 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.

2. 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, 2009, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:

Location of Description and Reserves (Country Independent Qualified Preparation Date of or Foreign Reserves Evaluator Evaluation Report Geographic Area)	Net Present Value of Future Net Revenue (before U.S. federal income taxes, 10% discount rate)
	Audited Evaluated Reviewed Total
Pennsylvania and Haas Petroleum Engineering Estimate of Reserves and West Virginia, USA Services, Inc. Future Net Revenue to the Enerplus Resources (East USA) Corporation Interest as of December 31, 2009, dated January 27, 2010	(US$ thousands) $ – $ 46,361 $ – $ 46,361

1. 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.

2. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

3. 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM C-1

Executed as to our report referred to above:

Haas Petroleum Engineering Services, Inc. Dallas, Texas, U.S.A. February 23, 2010

‘‘ Robert W. Haas ’’

Robert W. Haas, P.E. President

C-2 E NE RP LU S RE SOUR C ES 2009 ANNUAL INFORMATION FORM

APPENDIX D

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, 2009, 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 51-101F2 which are the reports of the independent qualified reserves evaluators on the reserves data; and

• (c) the content and filing of this report.

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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM D-1

ENERPLUS RESOURCES FUND

By EnerMark Inc.

‘‘ Gordon J. Kerr ’’ Gordon J. Kerr President & Chief Executive Officer

‘‘ Ian C. Dundas ’’ Ian C. Dundas Executive Vice President

‘‘ Harry B. Wheeler ’’

Harry B. Wheeler Director

‘‘ W.C. (Mike) Seth ’’ W.C. (Mike) Seth Director

March 12, 2010

D-2 EN ER PL US R ES OUR C ES 2009 ANNUAL INFORMATION FORM

APPENDIX E

Appendix E

Audit & Risk Management Committee Disclosure Pursuant to National 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 B. Hodgins (Chairman), Glen D. Roane and Harry B. Wheeler. Each member of the Committee is independent and financially literate within the meaning of National Instrument 52-110.

C. RELEVANT EDUCATION AND EXPERIENCE

Name (Director Since) Principal Occupation and Biography Robert B. Hodgins (B.A. (Business), C.A. Mr. Hodgins has been an independent businessman since November 2004. Prior (Director since November 2007) to that, Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust (a TSX and NYSE-listed energy trust) from 2002 to 2004. Prior to that, Other Public Directorships Mr. Hodgins held the position of Vice President and Treasurer of Canadian • AltaGas Income Trust (energy midstream services) Pacific Limited (a diversified energy, transportation and hotels company) from • Fairborne Energy Ltd. (oil and gas exploration and 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited production company) (a TSX and NYSE-listed energy transportation company) from 1993 to 1998. • MGM Energy Corp. (oil and gas exploration and Mr. Hodgins received a Bachelor of Arts in Business from the Richard Ivey School production company) of Business at the University of Western Ontario in 1975 and received a • Orion Oil & Gas Corporation (oil and gas Chartered Accountant designation and was admitted as a member of the Institute of Chartered Accountants of Ontario in 1977 and Alberta in 1991.

• Orion Oil & Gas Corporation (oil and gas	Chartered Accountant designation and was admitted as a member of the
exploration andproduction company)	Institute of Chartered Accountants of Ontario in 1977 and Alberta in 1991.
Mr. Glen D. Roane (B.A., MBA)	Mr. Roane is a corporate director and has served as a board member of many
(Director since June 2004)	TSX-listed companies including (in addition to those public entities listed
	herewith of which he currently serves as a director) Repap Enterprises Inc.,
Other Public Directorships	Ranchero Energy Inc., Forte Resources Inc., Valiant Energy Inc., Maxx

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 a director of GBC North American Fund Inc., a Canadian mutual fund corporation. 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.

• Badger Income Fund (provider of non-destructive excavation services)

• Destiny Resource Services Corp. (oil and gas service business)

• UTS Energy Corporation (oil sands company)

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM E-1

Name (Director Since)	Principal Occupation and Biography
Mr. Harry B. Wheeler (B.Sc. (Geology))	Mr. Wheeler has been the President of Colchester Investments Ltd., a private
(Director since January 2001)	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
Other Public Directorships	International Resources Ltd., in London, England and Denver, Colorado. He was
• Nil	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 2009 and 2008 were pre-approved by the Committee. Based on the Committee’s discussions with management and the independent auditors, the Committee is of the view that the provision of the non-audit services by Deloitte & Touche LLP described above is compatible with maintaining that firm’s independence from the Fund.

E. 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:

		2009		2008
		(in $	thousands)
Audit fees(1)	$	790.2	$	772.5
Audit-related fees(2)		–		–
Tax fees(3)		367.3		106.3
All other fees(4)		–		–
	$	1,157.5	$	878.8

Notes:

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

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

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

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

E-2 E NE RP LU S RE SOUR C ES 2009 ANNUAL INFORMATION FORM

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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM E-3

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 and shall include:

4. (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;

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

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

7. Oversee the independence of the external auditors by, among other things:

8. (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;

9. (b) reviewing and approving the Fund’s hiring policies regarding partners, employees and former partners and employees of current and former external auditors;

10. (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;

11. (d) Pre-approve the nature of non-audit related services and the fees thereon;

12. (e) conducting private sessions with the external auditors and encouraging direct communications between the Chairman of the Committee and the audit partner;

13. (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;

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

15. (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

1. 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;

E-4 E NE RP LU S RE SOUR C ES 2009 ANNUAL INFORMATION FORM

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

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

3. Receipt of certifications from the CEO and CFO; and

4. 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:

5. (a) obtain satisfactory answers from management following the review of the financial documents;

6. (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;

7. (c) the methods used to account for significant unusual transactions;

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

9. (e) management’s process for formulating sensitive accounting estimates and the reasonableness of these estimates;

10. (f) significant recorded and unrecorded audit adjustments;

11. (g) any material accounting issues among management and the external auditors;

12. (h) other matters required to be communicated to the Committee by the external auditors under generally accepted auditing standards;

13. (i) management’s acknowledgement of its responsibility towards the financial statements;

14. (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

15. (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

1. 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;

2. 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;

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

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

5. Review the management disclosure and oversight Committee’s CEO and CFO certification processes to ensure compliance with US and Canadian requirements;

6. 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; and

7. Review annually the report of the external auditor on the Fund’s internal controls 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.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM E-5

Review of Business Risks

1. 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

1. Review of appointment or dismissal of senior financial executives;

2. 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;

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

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

5. 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

6. 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 is also reviewed annually 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.

E-6 E NE RP LU S RE SOUR C ES 2009 ANNUAL INFORMATION FORM

APPENDIX F

Appendix F – Supplemental Information About Oil and Gas Producing Activities

The following disclosures including Proved reserves, future net cash flows, and costs incurred attributable to our conventional crude oil and natural gas operations and our SAGD-recoverable bitumen projects have been prepared in accordance with the provisions of the Financial Accounting Standards Board’s Accounting Standards Update (ASU) No. 2010-03 ‘‘ Extractive Activities – Oil and Gas (Topic) 932 (the ‘‘ ASU ’’).’’ This new guidance is primarily intended to modernize and update oil and gas disclosure requirements and to align them with current practices and changes in technology. The new standards also revised the definition of proved reserves and require the use of a 12 month average price to estimate proved reserves rather than a period end spot price as required in prior periods. The 12 month average price is calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12 month period prior to the end of the reporting period. The Fund prospectively adopted this guidance effective December 31, 2009 without prior period restatement.

A. PROVED 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’’ crude oil, natural gas, natural gas liquids and bitumen 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 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. Future fluctuations in prices and costs, production rates, or changes in political or regulatory environments could cause the Fund’s reserves to be materially different from that presented.

Proved reserves, proved developed reserves and proved undeveloped reserves are defined under the ASU. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulation. Proved Developed Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved Undeveloped Reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The Proved Reserves disclosed herein are determined according to the definition of ‘‘proved reserves’’ under NI 51-101 which may differ 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 ’’).

Subsequent to December 31, 2009, no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of Proved Reserves as of that date.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM F-1

The Fund’s December 31, 2009 Proved crude oil, natural gas and natural gas liquids reserves are located in western Canada, primarily in Alberta, British Columbia, Saskatchewan and Manitoba, as well as in the United States, primarily in the states of Montana, North Dakota, Wyoming, Pennsylvania, Utah and West Virginia. The Fund’s net Proved Reserves summarized in the following chart represent the Fund’s lessor royalty, overriding royalty, and working interest share of reserves, after deduction of any Crown, freehold and overriding royalties:

	Canada Oil and Natural NGLs Gas Bitumen (Mbbls) (MMcf) (Mbbls)	United States Oil and Natural NGLs Gas (Mbbls) (MMcf)	Total
			Oil and Natural NGLs Gas Bitumen
			(Mbbls) (MMcf) (Mbbls)
Proved Developed and Undeveloped Reserves at December 31, 2006	101,298 717,461 8,389 4 2,851 – – (2,587) – 1,411 18,387 – (275) 3,931 35 2,387 6,676 – (8,680) (72,262) – 96,145 674,457 8,424 5,241 296,849 – – – (8,424) 2,034 18,225 – (7,802) (57,449) – 1,939 2,699 – (8,958) (96,664) – 88,599 838,117 – 398 – – (1,019) (618) – 1,618 2,987 – 7,423 (265,677) – 85 184 – (8,580) (100,581) – 88,524 474,412 – 95,734 584,846 2,687 90,715 533,654 2,341 79,485 683,044 – 82,384 468,746 –	19,469 12,338 124 13,311 – – – – 292 6,193 5,744 4,722 (3,031) (3,435) 22,598 33,129 – – – – – – (1,820) 553 1,290 2,676 (2,852) (4,103) 19,216 32,255 – 3,537 – – 129 2,524 1,152 9,525 1,910 2,279 (2,496) (4,395) 19,911 45,725 18,977 11,961 19,707 26,839 18,664 28,462 17,604 36,061	120,767 729,799 8,389
Purchases of reserves in place Sales of reserves in place Discoveries and extensions Revisions of previous estimates Improved recovery Production			128 16,162 – – (2,587) – 1,411 18,387 – 17 10,124 35 8,131 11,398 – (11,711) (75,697) –
Proved Developed and Undeveloped Reserves at December 31, 2007			118,743 707,586 8,424
Purchases of reserves in place Sales of reserves in place Discoveries and extensions Revisions of previous estimates Improved recovery Production			5,241 296,849 – – – (8,424) 2,034 18,225 – (9,622) (56,896) – 3,229 5,375 – (11,810) (100,767) –
Proved Developed and Undeveloped Reserves at December 31, 2008			107,815 870,372 –
Purchases of reserves in place Sales of reserves in place Discoveries and extensions Revisions of previous estimates Improved recovery Production			398 3,537 – (1,019) (618) – 1,747 5,511 – 8,575 (256,152) – 1,995 2,463 – (11,076) (104,976) –
Proved Developed and Undeveloped Reserves at December 31, 2009			108,435 520,137 –
Proved Developed Reserves December 31, 2006 December 31, 2007 December 31, 2008 December 31, 2009			114,711 596,807 2,687 110,422 560,493 2,341 98,149 711,506 – 99,988 504,807 –

F-2 E NE RP LU S RE SO UR C ES 2009 ANNUAL INFORMATION FORM

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:

		2009		2008		2007
			(in $ thousands)
Capitalized costs(1)	$	7,673,238	$	7,322,721	$	5,245,528
Less accumulated depletion, depreciation and amortization		(4,879,015)		(4,005,780)		(1,970,467)
Net capitalized costs	$	2,794,223	$	3,316,941	$	3,275,061

Note:

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

C. COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in connection with oil and gas producing activities are presented in the table below. 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. Property acquisition costs for 2009 include the entire carry commitment relating to Enerplus’ 2009 Marcellus Acquisition. 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.

	For the Year Ended December 31, 2009
	Canada United States Total
Acquisition of properties: Proved Unproved Exploration costs Development costs Asset retirement costs	(in $ thousands) $ 2,636 $ – $ 2,636 59,664 487,121 546,785 29,489 4,990 34,479 195,040 40,974 236,014 25,633 (1,073) 24,560
	$ 312,462 $ 532,012 $ 844,474

	For the Year Ended December 31, 2008
	Canada United States Total
Acquisition of properties: Proved Unproved Exploration costs Development costs Asset retirement costs	(in $ thousands) $ 1,733,742 $ 115 $ 1,733,857 70,069 448 70,517 27,360 5,822 33,182 445,111 63,661 508,772 48,097 168 48,265
	$ 2,324,379 $ 70,214 $ 2,394,593

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM F-3

	For the Year Ended December 31, 2007
	Canada United States Total
Acquisition of properties: Proved Unproved Exploration costs Development costs Asset retirement costs	(in $ thousands) $ 10,215 $ 60,954 $ 71,169 212,154 915 213,069 33,994 13,770 47,764 231,889 91,557 323,446 52,179 262 52,441
	$ 540,431 $ 167,458 $ 707,889

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, 2009, 2008 and 2007:

	For the Year Ended December 31, 2009
	Canada United States Total
Revenue Sales(1) Deduct(2) Production Costs(3) Depletion, depreciation, amortization, accretion and impairment Current and Deferred income tax provision	(in $ thousands) $ 897,222 $ 168,241 $ 1,065,463 339,387 28,015 367,402 883,778 70,166 953,944 (192,902) 4,127 (188,775)
Results of operations for oil and gas producing activities	$ (133,041) $ 65,933 $ (67,108)
	For the Year Ended December 31, 2008
	Canada United States Total
Revenue Sales(1) Deduct(2) Production Costs(3) Depletion, depreciation, amortization, accretion and impairment Current and Deferred income tax provision (recovery)	(in $ thousands) $ 1,655,831 $ 265,579 $ 1,921,410 342,161 37,580 379,741 1,711,270 275,448 1,986,718 (375,056) 6,137 (368,919)
Results of operations for oil and gas producing activities	$ (22,544) $ (53,586) $ (76,130)
	For the Year Ended December 31, 2007
	Canada United States Total
Revenue Sales(1) Deduct(2) Production Costs(3) Depletion, depreciation, amortization, accretion and impairment Current and Deferred income tax provision	(in $ thousands) $ 1,025,822 $ 228,183 $ 1,254,005 286,248 10,000 296,248 299,217 103,752 402,969 70,827 30,204 101,031
Results of operations for oil and gas producing activities	$ 369,530 $ 84,227 $ 453,757

Notes:

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

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

(3) Production costs include transportation costs and state production taxes.

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E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVE QUANTITIES

The following information is based on crude oil, natural gas, natural gas liquids and bitumen 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.

It is expected that material revisions to some estimates of crude oil, natural gas, natural gas liquids and bitumen 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 and natural gas reserves:

	As at December 31, 2009
	Canada United States Total
Future cash inflows Future production costs Future development and asset retirement costs Future income tax expenses	(in $ millions) $ 6,902 $ 1,135 $ 8,037 3,320 280 3,600 513 96 609 201 152 353
Future net cash flows Deduction: 10% annual discount factor	$ 2,868 $ 607 $ 3,475 1,144 250 1,394
Standardized measure of discounted future net cash flows	$ 1,724 $ 357 $ 2,081

	As at December 31, 2008
	Canada United States Total
Future cash inflows Future production costs Future development and asset retirement costs Future income tax expenses	(in $ millions) $ 8,645 $ 891 $ 9,536 3,679 244 3,923 747 46 793 279 83 362
Future net cash flows Deduction: 10% annual discount factor	$ 3,940 $ 518 $ 4,458 1,562 177 1,739
Standardized measure of discounted future net cash flows	$ 2,378 $ 341 $ 2,719

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

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM 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:

		2009		2008		2007
				(in $ millions)
Beginning of year	$	2,719	$	3,990	$	3,578
Sales of oil and natural gas produced, net of production costs		(1,234)		(1,608)		(972)
Net changes in sales prices and production costs		328		(1,276)		1,197
Changes in previously estimated development costs incurred during the period		285		235		145
Changes in estimated future development costs		(134)		(135)		(221)
Extension, discoveries and improved recovery, net of related costs		54		63		416
Purchase of reserves in place		13		680		42
Sales of reserves in place		–		(27)		(4)
Net change resulting from revisions in previous quantity estimates		(115)		88		(8)
Accretion of discount		202		376		312
Net change in income taxes		(37)		333		(496)
End of year	$	2,081	$	2,719	$	3,990

F-6 E NE RP LU S RE SO UR C ES 2009 ANNUAL INFORMATION FORM

APPENDIX G

Appendix G – Information Regarding Enerplus Exchangeable Limited Partnership

INFORMATION CONCERNING ENERPLUS EXCHANGEABLE 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 EELP 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 (as amended by a filing completed on April 1, 2008) and on the EDGAR website at www.sec.gov on Form 6-K on February 20, 2008 (as amended by a filing completed on April 2, 2008).

General

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

The business of EELP 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

EELP is authorized to issue an unlimited number of EELP A Units and EELP Exchangeable LP Units. The EELP General Partner may, in respect of EELP, 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 EELP 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 EELP, whether voluntary or involuntary, or any other distribution of the assets of EELP among its partners for the purpose of winding-up its affairs: (a) the holders of EELP 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 EELP; and (b) the balance of the assets of EELP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Unit outstanding; and (ii) as to the remaining portion of such assets, to the holders of EELP A Units rateably in accordance with the number of EELP A Units held thereby.

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM G-1

EELP A Units

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

EELP Exchangeable LP Units

In 2006, EELP (then named Focus Limited Partnership) issued 10,000,000 EELP Exchangeable LP Units to securityholders of Profico Energy Management Ltd. (‘‘ Profico ’’) who elected to receive and were entitled to receive EELP Exchangeable LP 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 December 31, 2009 there were approximately 6,382,000 EELP Exchangeable LP Units issued and outstanding, exchangeable into an aggregate of approximately 2,712,000 Trust Units of the Fund. The EELP Exchangeable LP Units may also be issued in respect of other acquisitions made by EELP from time to time. The EELP General Partner shall ensure, in good faith and in its sole discretion, the economic equivalence of EELP Exchangeable LP Units to Trust Units, after giving effect to the 0.425 exchange ratio.

The principal terms of EELP Exchangeable LP Units are:

• (a) EELP Exchangeable LP 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 EELP Agreement, the EELP Support Agreement and the EELP Voting and Exchange Agreement. See below under ‘‘– EELP Voting and Exchange Agreement – Exchange Right ’’;

• (b) each EELP Exchangeable LP Unit entitles the holder thereof to receive non-interest bearing loans from EELP equal to cash distributions made by the Fund on a Trust Unit, multiplied by 0.425. See below under ‘‘ – Distribution Rights ’’;

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

• (d) the holders of EELP Exchangeable LP Units will not be entitled as such to receive notice of or to attend any meeting of the partners of EELP or to vote at any such meeting. However, holders of EELP Exchangeable LP 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 EELP Exchangeable LP Units or in respect of any other amendment to the applicable partnership agreement which will have an adverse impact on the holders of such EELP Exchangeable LP Units. See below under ‘‘ – Voting Rights ’’;

• (e) EELP Exchangeable LP Units will not be transferable except as set out below under ‘‘ – Transfer of EELP Exchangeable LP Units ’’; and

• (f) EELP will be entitled to acquire all of EELP Exchangeable LP Units in exchange for Trust Units in certain specified circumstances, including there being outstanding fewer than 1,000,000 EELP Exchangeable LP Units or in the event of certain transactions which may involve a change of control of the Fund. See below under ‘‘ – Redemption Right ’’.

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

Distribution Rights

Holders of EELP Exchangeable LP Units are entitled to receive, and EELP 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 EELP Exchangeable LP Unit:

• (a) in the case of a cash distribution declared on Trust Units, in an amount in cash for each EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units pursuant to these distribution entitlements will not constitute a distribution of profits or other compensation by way of income in respect of such EELP Exchangeable LP Units but rather will

G-2 EN ER PL US R ES OUR C ES 2009 ANNUAL INFORMATION FORM

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 EELP Exchangeable LP Units receiving the same, which loan will be repayable by such holder to EELP 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 EELP Exchangeable LP Units in respect of which the loans were made (pursuant to the Retraction Right or any redemption by EELP); (d) the business day prior to the purchase of EELP Exchangeable LP 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 EELP Exchangeable LP 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, EELP will make a distribution in respect of each EELP Exchangeable LP Unit equal to the amount of the loan outstanding in respect thereof. EELP will set off and apply the amount of any such distribution against the obligations of any holder of EELP Exchangeable LP Units under any loan outstanding in respect thereof and each holder of EELP Exchangeable LP Units will have the right to set off and apply any amount owed by such holder of EELP Exchangeable LP Units under any loan outstanding in respect thereof against the amount of any such distribution.

Transfer of EELP Exchangeable LP Units

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

Retraction Right

Pursuant to the Retraction Right, holders of EELP Exchangeable LP Units will be entitled at any time prior to January 8, 2017 to require EELP to redeem any or all of EELP Exchangeable LP Units held by such holder for the Retraction Price, which shall be satisfied by EELP causing to be delivered to such holder the EELP Exchangeable LP Unit Consideration (defined in Schedule ‘‘A’’ to the EELP Agreement as ‘‘Class B Unit Consideration’’) representing the Retraction Price.

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

EELP will thereafter cause the EELP Exchangeable LP Unit Consideration to be delivered to the holder of EELP Exchangeable LP Units. For greater clarity, the EELP Exchangeable LP Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each EELP Exchangeable LP 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 EELP, whether voluntary or involuntary, or any other distribution of the assets of EELP among its partners for the purpose of winding-up its affairs, a holder of EELP Exchangeable LP Units will be entitled, subject to applicable law, to receive from the assets of EELP, in respect of each such EELP Exchangeable LP Unit held on the Liquidation Date, the Liquidation Amount, which shall be satisfied by EELP causing to be delivered to such holder the EELP Exchangeable LP Unit Consideration representing the Liquidation Amount. For greater clarity, the EELP Exchangeable LP Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each EELP Exchangeable LP 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 EELP Exchangeable LP Units on the Liquidation Date all but not less than all of such holders’ EELP Exchangeable LP Units for the Liquidation Amount and, upon the exercise of this right, the holders thereof will be obligated to sell such EELP Exchangeable LP Units to the Fund or its applicable subsidiary. For the purposes of completing the purchase of EELP Exchangeable LP Units pursuant to the Liquidation Call

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM G-3

Right, the Fund or its applicable subsidiary will deposit or cause to be deposited with the transfer agent for such EELP Exchangeable LP Units, on or before the Liquidation Date, the EELP Exchangeable LP Unit Consideration representing the Liquidation Amount. Upon the surrender to the transfer agent by a holder of such EELP Exchangeable LP Units of its certificate(s) representing EELP Exchangeable LP Units, together with such other documents and instruments as may be required to effect a transfer of EELP Exchangeable LP Units pursuant to the EELP Agreement, the transfer agent will deliver the EELP Exchangeable LP Unit Consideration to which such holder is entitled. For greater clarity, the EELP Exchangeable LP Unit Consideration will consist, in part, of 0.425 of a Trust Unit for each EELP Exchangeable LP Unit subject to the Liquidation Call Right.

Redemption Right

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

For the purposes of the EELP Exchangeable LP Unit provisions, ‘‘Redemption Date’’ means the date, if any, established by the Board of Directors for the redemption by EELP of all but not less than all of the outstanding EELP Exchangeable LP Units (other than EELP Exchangeable LP 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 1,000,000 EELP Exchangeable LP Units outstanding (other than EELP Exchangeable LP 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 EELP Exchangeable LP Units, any issue or distribution of rights, options or warrants to acquire EELP Exchangeable LP Units (or securities exchangeable for or convertible into or carrying rights to acquire EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units and the Voting and Exchange Trustee as the Board of Directors may determine to be reasonably practicable in such circumstances;

• (b) a Trust Control Transaction occurs in respect of EELP, 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 EELP Exchangeable LP Units, in connection with such a Trust Control Transaction and that the redemption of all but not less than all of the outstanding EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units, to consider the EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units fail to take the necessary action at a meeting or other vote of holders of EELP Exchangeable LP Units, to approve or disapprove, as applicable, the Exempt EELP Exchangeable LP Unit Voting Event, in which case the redemption date shall be the business day following the day on which the holders of EELP Exchangeable LP Units fail to take such action,

G-4 EN ER PL US R ES OUR C ES 2009 ANNUAL INFORMATION FORM

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 EELP Exchangeable LP Units shall not affect the validity of any such redemption.

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

Automatic Redemption

Holders of EELP Exchangeable LP Units are obligated to notify EELP 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 EELP Exchangeable LP Units, all but not less than all of such holder’s EELP Exchangeable LP Units will be and be deemed to be transferred to EELP for the Automatic Redemption Price per EELP Exchangeable LP Unit, which shall be satisfied by EELP depositing or causing to be deposited with the transfer agent for such EELP Exchangeable LP Units the EELP Exchangeable LP Unit Consideration representing the Automatic Redemption Price. Upon the surrender to the transfer agent by a holder of such EELP Exchangeable LP Units of its certificate(s) representing EELP Exchangeable LP Units, together with such other documents and instruments as may be required to effect a transfer of EELP Exchangeable LP Units pursuant to the EELP Agreement, the transfer agent will deliver the EELP Exchangeable LP Unit Consideration to which such holder is entitled.

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

EELP AGREEMENT

Voting Rights

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

Pursuant to the Fund’s Trust Indenture, the Special Voting Right has been issued in conjunction with EELP Exchangeable LP 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 EELP Voting and Exchange Agreement, each of the holders of EELP Exchangeable LP 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 EELP Exchangeable LP Units are exchangeable. The Special Voting Right issued to the Voting and Exchange Trustee by the Fund entitles the holders of EELP Exchangeable LP Units to 0.425 of a vote at meetings of the Fund’s unitholders for each EELP Exchangeable LP Unit, but has none of the other rights attached to Trust Units. See ‘‘ – EELP Voting and Exchange Agreement – Voting Rights ’’.

Amendment and Approval

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

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

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

E NE RP LUS RE S OURCE S 2009 ANNUAL INFORMATION FORM G-5

• (c) no amendment shall be made to the EELP Agreement which would have the effect of adding, changing or removing any right, privilege, restriction or condition attaching to EELP Exchangeable LP Units, or which would have an adverse impact on the holders of EELP Exchangeable LP Units unless such amendment is approved by a class vote of 66[2] ⁄3% of the holders of EELP Exchangeable LP Units; and

• (d) no amendment shall be made which would have the effect of adversely affecting the rights and obligations of the EELP 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 EELP Agreement within 30 days of the effective date of the amendment.

EELP 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 EELP 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 June 9, 2008 and on the EDGAR website at www.sec.gov on Form 6-K on June 11, 2008.

Voting Rights

In accordance with the EELP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units in connection with the exercise by that holder of the Exchange Right (unless the Fund shall not have delivered the EELP Exchangeable LP Unit Consideration in exchange therefor); (b) the occurrence of the automatic exchange of EELP Exchangeable LP Units for Trust Units pursuant to the Automatic Exchange Right; (c) the redemption of EELP Exchangeable LP Units pursuant to EELP Exchangeable LP Units provisions or upon the effective date of the liquidation, dissolution or winding-up of EELP pursuant EELP Exchangeable LP Units provisions; (d) the automatic redemption of EELP Exchangeable LP Units pursuant to EELP Exchangeable LP Units provisions; (e) the purchase of EELP Exchangeable LP Units from the holder by EELP; or (f) the purchase of EELP Exchangeable LP Units from the holder by the Fund or its applicable subsidiary pursuant to the Liquidation Call Right pursuant to EELP Exchangeable LP Units provisions.

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

G-6 EN ER PL US R ES OUR C ES 2009 ANNUAL INFORMATION FORM

Exchange Right

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

Exchange Right Subsequent to Retraction

Where a holder of EELP Exchangeable LP Units has elected to exercise its Retraction Right in respect of any or all of its EELP Exchangeable LP Units, and EELP 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 EELP 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 EELP Exchangeable LP Units describing the Automatic Exchange Right. Immediately prior to the effective time of the Liquidation Event, and in order to enable the holders of EELP Exchangeable LP 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 EELP Exchangeable LP Units for Trust Units based upon the EELP Exchangeable LP Unit Price applicable at that time, which for greater certainty will be on the basis of 0.425 of a Trust Unit for each EELP Exchangeable LP Unit.

EELP 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 EELP 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.

The EELP Support Obligation

Under the EELP Support Agreement, so long as any EELP Exchangeable LP 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 EELP, 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 EELP Exchangeable

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LP Units (other than EELP Exchangeable LP Units owned by the Fund 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 EELP Exchangeable LP Units, or a redemption of EELP Exchangeable LP Units by EELP; 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 EELP or any other distribution of the assets of EELP 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 EELP or any other distribution of the assets of EELP among its partners for the purpose of winding-up its affairs.

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

• (a) 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

• (b) 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

• (c) 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units.

In addition, the Fund may not without the prior approval of EELP and the holders of EELP Exchangeable LP 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, EELP Exchangeable LP 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 EELP Exchangeable LP Units are not redeemed by EELP, 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 EELP Exchangeable LP 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).

The EELP Support Agreement also provides that, as long as any outstanding EELP Exchangeable LP 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 EELP and from the holders of EELP Exchangeable LP Units pursuant to EELP Exchangeable LP Units provisions, remain the direct or indirect beneficial owner of all issued and outstanding voting interests in the capital of EELP and the EELP 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 EELP Exchangeable LP 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 EELP Exchangeable LP Units), the EELP Support Agreement may not be amended or modified except by an agreement in writing executed by EELP, the EELP General Partner, and the Fund and approved by the holders of EELP Exchangeable LP Units pursuant to EELP Exchangeable LP Units provisions.

G-8 EN ER PL US R ES OUR C ES 2009 ANNUAL INFORMATION FORM

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

Upon notice from EELP of any event that requires EELP to cause to be delivered Trust Units to any holder of EELP Exchangeable LP 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 EELP Exchangeable LP Units as EELP 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 EELP Exchangeable LP 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 EELP GENERAL PARTNER UNDER THE EELP SUPPORT AGREEMENT AND THE EELP VOTING AND EXCHANGE AGREEMENT

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

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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