EXHIBIT 99.1

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GRAPHIC

(as successor issuer to Enerplus Resources Fund)

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ANNUAL INFORMATION FORM
For the year ended December 31, 2010

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March 11, 2011

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TABLE OF CONTENTS

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|------------------------------------------------------------------------------------------------ | -------------------------------------------------------------------------------------------- | ----
|GLOSSARY OF TERMS                                                                                |                                                                                              | i   
|ABBREVIATIONS AND CONVERSIONS                                                                    |                                                                                              | iii 
|PRESENTATION OF ENERPLUS' OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION             |                                                                                              | iv  
|                                                                                                 | Note to Reader Regarding Oil and Gas Information, Definitions and National Instrument 51-101 |     
|                                                                                                 | Disclosure of Reserves and Production Information                                            |     
|                                                                                                 | Barrels of Oil and Cubic Feet of Gas Equivalent                                              |     
|                                                                                                 | Disclosure of Contingent Resources                                                           |     
|                                                                                                 | Interests in Reserves, Production, Wells and Properties                                      |     
|                                                                                                 | Reserves Categories and Levels of Certainty for Reported Reserves                            |     
|                                                                                                 | Development and Production Status                                                            |     
|                                                                                                 | Description of Price and Cost Assumptions                                                    |     
|PRESENTATION OF ENERPLUS' FINANCIAL INFORMATION                                                  |                                                                                              | vii 
|FORWARD-LOOKING STATEMENTS AND INFORMATION                                                       |                                                                                              | viii
|CORPORATE STRUCTURE                                                                              |                                                                                              | 1   
|                                                                                                 | Enerplus Corporation                                                                         |     
|                                                                                                 | Material Subsidiaries                                                                        |     
|                                                                                                 | Organizational Structure                                                                     |     
|                                                                                                 | Corporate Structure Prior to January 1, 2011                                                 |     
|GENERAL DEVELOPMENT OF THE BUSINESS                                                              |                                                                                              | 3   
|                                                                                                 | Developments in the Past Three Years                                                         |     
|                                                                                                 | Conversion from an Income Trust to a Corporation                                             |     
|BUSINESS OF ENERPLUS                                                                             |                                                                                              | 5   
|                                                                                                 | Overview                                                                                     |     
|                                                                                                 | Summary of Principal Production Locations                                                    |     
|                                                                                                 | Capital Expenditures and Costs Incurred                                                      |     
|                                                                                                 | Exploration and Development Activities                                                       |     
|                                                                                                 | Oil and Natural Gas Wells and Unproved Properties                                            |     
|                                                                                                 | Enerplus' Resource Play Types                                                                |     
|                                                                                                 | Equity Investments                                                                           |     
|                                                                                                 | Quarterly Production History                                                                 |     
|                                                                                                 | Quarterly Netback History                                                                    |     
|                                                                                                 | Abandonment and Reclamation Costs                                                            |     
|                                                                                                 | Tax Horizon                                                                                  |     
|                                                                                                 | Marketing Arrangements and Forward Contracts                                                 |     
|OIL AND NATURAL GAS RESERVES                                                                     |                                                                                              | 20  
|                                                                                                 | Summary of Reserves                                                                          |     
|                                                                                                 | Forecast Prices and Costs                                                                    |     
|                                                                                                 | Constant Prices and Costs                                                                    |     
|                                                                                                 | Undiscounted Future Net Revenue by Reserves Category                                         |     
|                                                                                                 | Net Present Value of Future Net Revenue by Reserves Category and Production Group            |     
|                                                                                                 | Estimated Production for Gross Reserves Estimates                                            |     
|                                                                                                 | Future Development Costs                                                                     |     
|                                                                                                 | Reconciliation of Reserves                                                                   |     
|                                                                                                 | Undeveloped Reserves                                                                         |     
|                                                                                                 | Significant Factors or Uncertainties                                                         |     
|                                                                                                 | Proved and Probable Reserves Not on Production                                               |     
|SUPPLEMENTAL OPERATIONAL INFORMATION                                                             |                                                                                              | 37  
|                                                                                                 | Health, Safety and Environment                                                               |     
|                                                                                                 | Insurance                                                                                    |     
|                                                                                                 | Personnel                                                                                    |     
|DESCRIPTION OF CAPITAL STRUCTURE                                                                 |                                                                                              | 39  
|                                                                                                 | Common Shares                                                                                |     
|                                                                                                 | Preferred Shares                                                                             |     
|                                                                                                 | Shareholder Rights Plan                                                                      |     
|                                                                                                 | Senior Unsecured Notes                                                                       |     
|                                                                                                 | Bank Credit Facility                                                                         |     
|DIVIDENDS AND DISTRIBUTIONS                                                                      |                                                                                              | 41  
|                                                                                                 | Dividend Policy and History                                                                  |     
|                                                                                                 | Dividend Reinvestment Plan                                                                   |     
|INDUSTRY CONDITIONS                                                                              |                                                                                              | 42  
|                                                                                                 | Overview                                                                                     |     
|                                                                                                 | Pricing and Marketing  Oil                                                                  |     
|                                                                                                 | Pricing and Marketing  Natural Gas                                                          |     
|                                                                                                 | The North America Free Trade Agreement                                                       |     
|                                                                                                 | Royalties and Incentives                                                                     |     
|                                                                                                 | Land Tenure                                                                                  |     
|                                                                                                 | Environmental Regulation                                                                     |     
|                                                                                                 | Worker Safety                                                                                |     
|RISK FACTORS                                                                                     |                                                                                              | 46  
|MARKET FOR SECURITIES                                                                            |                                                                                              | 56  
|DIRECTORS AND OFFICERS                                                                           |                                                                                              | 57  
|                                                                                                 | Directors of the Corporation                                                                 |     
|                                                                                                 | Officers of the Corporation                                                                  |     
|                                                                                                 | Common Share Ownership                                                                       |     
|                                                                                                 | Conflicts of Interest                                                                        |     
|                                                                                                 | Audit & Risk Management Committee Disclosure                                                 |     
|LEGAL PROCEEDINGS AND REGULATORY ACTIONS                                                         |                                                                                              | 59  
|INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                                       |                                                                                              | 59  
|MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS                         |                                                                                              | 60  
|INTERESTS OF EXPERTS                                                                             |                                                                                              | 60  
|TRANSFER AGENT AND REGISTRAR                                                                     |                                                                                              | 61  
|ADDITIONAL INFORMATION                                                                           |                                                                                              | 61  
|APPENDIX A  REPORTS 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 OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE                        |                                                                                              | C-1 
|APPENDIX D  AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE PURSUANT TO NATIONAL INSTRUMENT 52-110 |                                                                                              | D-1 
|APPENDIX E  SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES                     |                                                                                              | E-1 

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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".

"ABCA" means theBusiness Corporations Act(Alberta), as amended;

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

"Bank Credit Facility" means, as of December 31, 2010, Enerplus' $1.0 billion unsecured, covenant-based revolving credit facility
with a syndicate of financial institutions: see "Material Contracts and Documents Affecting the Rights of Securityholders";

"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;

"Common Shares" means the common shares in the capital of the Corporation;

"Conversion" means the conversion of Enerplus' business from an income trust structure (with the parent entity being the Fund) to a corporate structure
(with the parent entity being the Corporation) effective January 1, 2011 pursuant to a plan of arrangement under the ABCA;

"Corporation" means Enerplus Corporation, a corporation amalgamated under the ABCA;

"Credit Facilities" means, collectively, the Bank Credit Facility and the Senior Unsecured Notes: see "Material Contracts and
Documents Affecting the Rights of Securityholders".

"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;

"EELP" means Enerplus Exchangeable Limited Partnership, formerly a limited partnership established under the laws of Alberta and a subsidiary of the
Fund, which was dissolved on January 1, 2011 in connection with the Conversion;

"Enerplus" means (i) on and after January 1, 2011, the Corporation and, where the context applies, its subsidiaries, taken as a
whole, and (ii) prior to January 1, 2011, the Fund and its subsidiaries, taken as a whole;

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

"Fund" means Enerplus Resources Fund, formerly a trust formed pursuant to the laws of Alberta that was dissolved on January 1, 2011 in
connection with the Conversion, and which was the predecessor issuer to the Corporation;

"GAAP" means generally accepted accounting principles;

"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 contingent resources in the Marcellus
Properties prepared by Haas effective December 31, 2010, utilizing commodity price forecasts of McDaniel (for internal consistency in Enerplus' reserves reporting) as of
January 1, 2011;

"IFRS" means international financial reporting standards, being the standards adopted by the International Accounting Standards Board, as amended from
time to time;

"Laricina" means Laricina Energy Ltd., a private corporation organized under the ABCA;

"Marcellus Carry Amount" has the meaning assigned thereto under "General Development of the
Business  Developments in the Past Three Years  Developments in 2009  Acquisition
of Interests in the Marcellus Shale Gas Play";

"Marcellus JDA" means the Joint Development Agreement dated September 1, 2009 among Enerplus USA and the vendors of the interests acquired
by Enerplus in the Marcellus shale gas resource play on September 1, 2009;

"McDaniel" means McDaniel & Associates Consultants Limited, independent petroleum consultants;

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"McDaniel Reports" means, collectively, the independent engineering evaluations of Enerplus' oil, NGLs and natural gas reserves in Canada and the
western United States prepared by McDaniel effective December 31, 2010, utilizing commodity price forecasts of McDaniel as of January 1, 2011;

"MD&A" means management's discussion and analysis;

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

"NYSE" means the New York Stock Exchange;

"SAGD" means steam assisted gravity drainage, anin situproduction process used to recover bitumen from
oil sands;

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

"Senior Unsecured Notes" means, as at December 31, 2010, the US$459 principal amount and Cdn$40 principal amount of senior unsecured notes
issued by Enerplus: see "Description of Capital Structure  Senior Unsecured Notes" and
"Material Contracts and Documents Affecting the Rights of Securityholders";

"Shareholder Rights Plan" means the shareholder rights plan agreement between the Corporation and Computershare Trust Company of Canada, as rights
agent, dated effective January 1, 2011;

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

"Tax Act" means theIncome 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 Units" means the former trust units of the Fund, each of which represented an equal undivided beneficial interest in the Fund and which were
exchanged on a one-for-one basis for Common Shares pursuant to the Conversion; and

"TSX" means the Toronto Stock Exchange.

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Abbreviations and Conversions

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

|API       |  | American Petroleum Institute                                                                                                            
|--------- |  | ----------------------------------------------------------------------------------------------------------------------------------------
|bbls      |  | barrels, with each barrel representing 34.972 imperial gallons or 42 U.S. gallons                                                       
|bbls/day  |  | barrels per day                                                                                                                         
|Bcf       |  | billion cubic feet                                                                                                                      
|Bcf/day   |  | billion cubic feet per day                                                                                                              
|BcfGE(1)  |  | one billion cubic feet of natural gas equivalent                                                                                        
|BOE(1)    |  | barrels of oil equivalent                                                                                                               
|BOE/day   |  | barrels of oil equivalent per day                                                                                                       
|Mbbls     |  | one thousand barrels                                                                                                                    
|MBOE(1)   |  | one thousand barrels of oil equivalent                                                                                                  
|Mcf       |  | one thousand cubic feet                                                                                                                 
|Mcf/day   |  | one thousand cubic feet per day                                                                                                         
|McfGE(1)  |  | one thousand cubic feet of natural gas equivalent                                                                                       
|McfGE/day |  | one thousand cubic feet of natural gas equivalent per day                                                                               
|MMbbls    |  | one million barrels                                                                                                                     
|MMBOE(1)  |  | one million barrels of oil equivalent                                                                                                   
|MMbtu     |  | one million British Thermal Units                                                                                                       
|MMcf      |  | one million cubic feet                                                                                                                  
|MMcf/day  |  | one million cubic feet per day                                                                                                          
|NGLs      |  | natural gas liquids                                                                                                                     
|NYMEX     |  | the New York Mercantile Exchange                                                                                                        
|TcfGE(1)  |  | one trillion cubic feet of natural gas equivalent                                                                                       
|WTI       |  | West Texas Intermediate crude oil that serves as the benchmark crude oil for the NYMEX crude oil contract delivered in Cushing, Oklahoma

Note:

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 ByMcf

cubic metres

28.174cubic metres

cubic feet

35.494bbls

cubic metres

0.159cubic metres

bbls

6.293feet

metres

0.305metres

feet

3.281miles

kilometres

1.609kilometres

miles

0.621acres

hectares

0.4047hectares

acres

2.471


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Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information

NOTE TO READER REGARDING OIL AND GAS INFORMATION, DEFINITIONS AND NATIONAL INSTRUMENT 51-101

The oil and gas reserves and operational information of Enerplus contained in this Annual Information Form contains the information required to be included in
the Statement of Reserves Data and Other Oil and Gas Information pursuant to NI 51-101 adopted by the Canadian securities regulatory authorities. Readers should also refer to
the Reports on Reserves Data by McDaniel attached hereto as Appendix A, the Report on Reserves Data by Haas attached as Appendix B and the Report of Management and Directors on
Oil and Gas Disclosure attached hereto as Appendix C. The effective date for the Statement of Reserves Data and Other Oil and Gas Information contained in this Annual Information Form is
December 31, 2010 and the preparation date for such information is March 11, 2011. 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  Summary 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 each 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

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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.

Notwithstanding
the above, Enerplus has included as Appendix E 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
Activities  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 McfGEs, BcfGEs and TcfGEs. BOEs, MBOEs, MMBOEs, McfGEs, MMcfGEs, BcfGEs and TcfGEs 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" which relate to Enerplus' interests in its Bakken/Tight Oil,
Marcellus and Crude Oil Waterflood resource plays.

"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.

The
contingent resource estimates in this Annual Information Form are presented as the "best estimate" of the quantity that will actually be recovered,
meaning that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50%
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.

Resources
and contingent resources do not constitute, and should not be confused with, reserves. See "Business of Enerplus  Enerplus'
Resource Play Types  Marcellus Shale Gas", "Business of
Enerplus  Enerplus' Resource Play Types  Bakken/Tight Oil", "Business of
Enerplus  Enerplus Resource Play Types  Crude Oil Waterflood" and "Risk
Factors  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:

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"net" means:

"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:

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.

"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.

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DESCRIPTION OF PRICE AND COST ASSUMPTIONS

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

"Constant prices and costs" means, unless expressly noted otherwise, prices and costs used in an estimate that are the arithmetic average of the
first-day-of-the-month price of the applicable commodity for each of the twelve months in 2010, held constant throughout the estimated lives of the
properties to which the estimate applies.

Presentation of Enerplus' Financial Information

The financial information included or referred to in this Annual Information Form has been prepared in accordance with Canadian GAAP. Canadian GAAP differs in
some significant respects from U.S. GAAP and therefore this financial information may not be comparable to the financial information of U.S. companies. The principal differences as they
apply to the Fund are summarized in Note 16 to Enerplus' audited consolidated financial statements for the year ended December 31, 2010, which are available on the
Corporation's SEDAR profile at www.sedar.com, on the Corporation's EDGAR profile at www.sec.gov as part of the annual report on
Form 40-F filed by the Corporation with the SEC together with this Annual Information Form, and on the Corporation's 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. On December 31, 2010, the exchange rate for one Canadian dollar, expressed in U.S. dollars and based upon the noon buying rate of the Bank of Canada, was US$1.0054.

All
references to "Enerplus' audited consolidated financial statements for the year ended December 31, 2010" and "Enerplus' MD&A for the year ended December 31, 2010" refer
to such documents as filed by the Corporation as successor issuer to the Fund as it existed at December 31, 2010.

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Forward-Looking Statements and Information

This Annual Information Form contains certain forward-looking statements and forward-looking information (collectively, "forward-looking information") within
the meaning of applicable securities laws 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", "guidance", "objective", "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 information. Enerplus believes the expectations reflected in such forward-looking information are reasonable but no
assurance can be given that these expectations will prove to be correct, and such forward-looking information included in this Annual Information Form should not be unduly relied upon. Such
forward-looking information speaks 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 information,
except as required by applicable laws.

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

The
forward-looking information contained in this 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 and gas 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 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 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:

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Many
of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in Enerplus' MD&A for the year ended
December 31, 2010, which is available through the internet on the Corporation's SEDAR profile at www.sedar.com, on the Corporation's EDGAR profile 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 the Corporation's 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 the Corporation files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the
Corporation or electronically on the internet on the Corporation's SEDAR profile at www.sedar.com, on the Corporation's EDGAR profile at
www.sec.gov and on the Corporation's website at www.enerplus.com.

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AIF

ENERPLUS CORPORATION(as successor issuer to Enerplus Resources Fund)Annual Information FormFor the year ended
December 31, 2010

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As described further under "General Development of the Business  Conversion from an Income Trust to a
Corporation", on January 1, 2011 Enerplus converted its business from an income trust structure, with the parent entity being the Fund, to a corporate
structure, with the parent entity being the Corporation, pursuant to the Conversion. The Fund was dissolved on January 1, 2011 and the Corporation is the "successor issuer" of the Fund
within the meaning of National Instrument 44-101Short Form Prospectus Distributionsof the Canadian Securities Administrators.
Accordingly, where applicable and except as otherwise noted, all information in this Annual Information Form is presented after giving effect to the Conversion.

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Corporate Structure

ENERPLUS CORPORATION

The Corporation was incorporated on August 12, 2010 under the ABCA for the purposes of participating in the Conversion. As part of the plan of
arrangement under the ABCA pursuant to which the Conversion was effected, the Corporation was amalgamated with several other former direct and indirect subsidiaries of the Fund on
January 1, 2011 and continued as the Corporation. See "General Development of the Business  Developments in the Past Three
Years  Conversion from an Income Trust to a Corporation". The head, principal and registered office of the Corporation 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 Common Shares are currently traded on the TSX and the NYSE under the symbol "ERF".

MATERIAL SUBSIDIARIES

As of January 1, 2011, the Corporation's material subsidiaries were Enerplus Partnership and Enerplus USA.

Enerplus
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 the Partnership and Enerplus USA are directly and indirectly owned by the Corporation.

ENERPLUS2010 ANNUAL INFORMATION
FORM1

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ORGANIZATIONAL STRUCTURE

The simplified organizational structure of Enerplus as of January 1, 2011, following completion of the Conversion and related internal
reorganization on that date, is set forth below.

GRAPHIC

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Note:

CORPORATE STRUCTURE PRIOR TO JANUARY 1, 2011

Prior to the Conversion effective January 1, 2011, Enerplus carried on its business in the form of an income trust with the parent entity being
the Fund. The Fund was an unincorporated trust organized under the laws of Alberta, which carried on business through its operating subsidiaries. As of the end of 2010, the material subsidiaries of
the Fund were EnerMark Inc., Enerplus Resources Corporation (each an ABCA corporation), Enerplus Commercial Trust (an unincorporated Alberta trust), FET Operating Partnership
(an Alberta partnership) and Enerplus USA. As part of the Conversion and related internal reorganization, EnerMark Inc. and Enerplus Resources Corporation were amalgamated with several
other former direct and indirect subsidiaries of the Fund, including Enerplus Corporation, to continue as the Corporation, and Enerplus Commercial Trust and FET Operating Partnership
were dissolved.

2      ENERPLUS2010 ANNUAL INFORMATION
FORM

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General Development of the Business

DEVELOPMENTS IN THE PAST THREE YEARS

Developments in 2008

Acquisition of Focus Energy Trust

On February 13, 2008, Enerplus completed its acquisition of Focus Energy Trust ("Focus") pursuant
to a plan of arrangement under the ABCA. Pursuant to the arrangement, Enerplus acquired all of the assets and assumed all of the liabilities of Focus, Focus unitholders received 0.425 of a Trust Unit
for each Focus trust unit, and all of the trust units of Focus were redeemed. Enerplus issued an aggregate of 30,149,752 Trust Units to former Focus unitholders in the 2008 transaction.
Additionally, Enerplus assumed 9,087,000 exchangeable limited partnership units of Focus Limited Partnership (a subsidiary of Focus, subsequently renamed EELP), which became exchangeable
into 3,861,833 Trust Units as a result of the transaction.

Disposition of Joslyn Oil Sands Lease

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 oil sands lease, 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 in its 15% interest in
the Joslyn oil sands lease from its inception in 2002 until Enerplus sold its interest in 2008.

Developments in 2009

Acquisition of Interests in the Marcellus Shale Gas Play

On September 1, 2009, Enerplus (through the Fund's indirect wholly-owned subsidiary, Enerplus USA) acquired an average 21.5% working interest in
approximately 540,000 gross acres within the Marcellus shale natural gas play in the northeastern United States, the majority of which was located in Pennsylvania with certain interests
in Maryland and West Virginia. Total consideration for the acquisition was approximately US$411.0 million. The transaction had an effective date of May 1, 2009. The acquisition
was structured as two components, with one portion of the interests conveyed to Enerplus upon closing on September 1, 2009 and the remaining portion conveyed to Enerplus pursuant to the
Marcellus JDA, as described in further detail below.

At
the September 1, 2009 closing, Enerplus acquired an approximate 8.6% working interest in the subject Marcellus properties for cash consideration of US$164.4 million, which was
paid at closing. Enerplus and the vendors of the interests also entered into the Marcellus JDA on the closing date of the transaction, under which Enerplus acquired an additional approximate 12.9%
working interest in the subject Marcellus properties. Under the terms of the Marcellus JDA, the consideration of US$246.6 million (the "Marcellus Carry
Amount") for these additional working interests is paid over time as a "carry" and represents 50% of the vendors' share of the future well drilling and completion costs on the
subject Marcellus properties until the Marcellus Carry Amount has been fully expended. As of December 31, 2010, the remaining Marcellus Carry Amount was approximately
US$147 million. Based on existing future drilling and completion plans, Enerplus anticipates the Marcellus Carry Amount will be spent by 2012.

For
a description of Enerplus' interest in the Marcellus 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. Enerplus also 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/day.

ENERPLUS2010 ANNUAL INFORMATION
FORM3

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Developments in 2010

Acquisition of Additional Bakken Properties in North Dakota

On October 15, 2010, Enerplus acquired an additional 46,500 net acres (72 sections) of land in the Fort Berthold area of Dunn and
McKenzie counties in North Dakota. These lands were directly adjacent to Enerplus' existing land holdings in this area and are prospective for light crude oil in the Bakken and Three Forks formations.
The purchase price was US$468.7 million (before closing adjustments) and was funded through Enerplus' Bank Credit Facility. Throughout 2010, Enerplus completed additional acquisitions in the
Fort Berthold area, resulting in total acquisitions in the Fort Berthold area in 2010 (including the October 15, 2010 acquisition described above) of 58,921 net acres, including
production of 1,900 BOE/day, for an aggregate purchase price of $588.0 million. For a description of Enerplus' interest in the Bakken resource play, see "Business
of Enerplus  Enerplus' Resource Play Types  Bakken/Tight Oil".

Acquisition of Additional Operated Marcellus Properties

On August 23, 2010, Enerplus purchased 58,500 net acres of undeveloped land in the Marcellus shale natural gas play in West Virginia and
Maryland. The acreage is predominantly located in Preston County in West Virginia and Garrett County in Maryland and created a new, concentrated land position that Enerplus operates with an average
90% working interest. These new lands are in emerging areas with limited existing development. In total, Enerplus spent $169.3 million on property acquisitions in the Marcellus shale gas play
in 2010 (in addition to expenditures of $92.3 million contributed towards the Marcellus Carry Amount), acquiring the two key operated areas described above and acquiring a total of
approximately 75,317 net acres of undeveloped land, of which 70,833 is operated by Enerplus.

Sale of Non-Core Conventional Assets and Additional Acquisitions

In 2010, Enerplus executed on its strategy to sell non-core conventional assets in order to improve its focus and operational efficiency. During the
year, Enerplus sold approximately 10,400 BOE/day of production for approximately $465.2 million. The proceeds from these sales were used to retire outstanding debt under Enerplus' Bank
Credit Facility.

In
addition to the acquisitions described above, in 2010 Enerplus purchased approximately 104,500 net acres of prospective land contiguous to its existing holdings in the Freda Lake, Neptune
and Oungre areas of the Saskatchewan Bakken play for $118.7 million. Enerplus also acquired approximately 36,100 net acres of undeveloped land in the British Columbia Deep Basin for
$25.9 million.

Sale of Kirby Oil Sands Lease

On October 1, 2010, Enerplus sold 100% of its Kirby SAGD oil sands lease for proceeds of $404.8 million. Enerplus acquired a 100% working
interest in the Kirby lease in 2007 for $203.1 million and since that time had invested an additional $58 million in the Kirby lease to further delineate and identify the bitumen
resource on the lease. Proceeds from the sale were used to retire outstanding debt under Enerplus' Bank Credit Facility.

CONVERSION FROM AN INCOME TRUST TO A CORPORATION

On October 31, 2006, the Canadian Federal Minister of Finance proposed to subject certain types of publicly traded mutual fund trusts, such as the
Fund, to tax at rates comparable to the combined federal and provincial corporate tax rates beginning in the 2011 tax year. The legislation governing the tax on mutual fund trusts became law on
June 22, 2007.

As
a result, on January 1, 2011, Enerplus completed the Conversion pursuant to a plan of arrangement under the ABCA. The Conversion, together with a related internal corporate
reorganization, resulted in the business and structure of Enerplus being reorganized from an income trust, with the parent entity being the Fund, into a corporate structure, with the parent entity
being the Corporation. The plan of arrangement was approved by the unitholders of the Fund and EELP on December 9, 2010. Pursuant to the plan of arrangement, holders of the Fund's Trust
Units received one Common Share for each Trust Unit held, and holders of EELP exchangeable Class B limited partnership units received 0.425 of a Common Share for each EELP unit held. As part of
the Conversion and related reorganization transactions, the Fund and EELP were dissolved, all of the outstanding Trust Units and EELP units were cancelled and the Corporation continued as the
successor issuer to the Fund. The business, directors and management of the Corporation following completion of the Conversion are the same as the business of the Fund and the directors and management
of the Fund (through its administrator, EnerMark Inc.) immediately before completion of the Conversion. As a result of the Conversion, the Corporation is a reporting issuer in each of the
provinces and territories of Canada and each of the Fund and EELP are no longer reporting issuers in such jurisdictions.

4      ENERPLUS2010 ANNUAL INFORMATION
FORM

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Business of Enerplus

OVERVIEW

2010 was a transition year for Enerplus as it continued to move from an income model to a growth and income-oriented model in anticipation of the Conversion.
During this transition, Enerplus was focused on delivering operational results, repositioning its asset base and adding key leadership and technical skills. 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 2011.

Enerplus
has realigned its asset base to include not only mature income-oriented assets but also early stage, growth-oriented assets. In 2010, Enerplus acquired additional interests in the Marcellus
shale gas play in the U.S., the Bakken play in both North Dakota and southeastern Saskatchewan, and the Deep Basin region of Alberta and British Columbia. Enerplus believes that it has accumulated a
meaningful portfolio of prospects that will provide organic growth potential in the future. 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. In 2010, Enerplus disposed of approximately 10,400 BOE/day of non-core conventional oil and gas
production. In addition, Enerplus sold its Kirby SAGD oil sands property. See "General Development of the Business  Developments in the
Past Three Years  Developments in 2010" above.

Enerplus'
acquisition and development activities are generally focused on "resource plays", which are typically large and aerially extensive accumulations of discovered oil and natural gas with
limited geological risk. Resource plays typically 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' five resource play types include: (i) Bakken/Tight Oil in Montana, North Dakota and southeastern 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; and (v) Shallow Gas (which includes some shallow coalbed methane properties) in southeastern and central Alberta and southwestern Saskatchewan. 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, 2010, (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 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 primarily in western Canada in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, and in the United States in
the states of Montana, North Dakota, Maryland, Pennsylvania, West Virginia, 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, 2010 from Enerplus' properties consisted of approximately 42% crude oil and NGLs and 58% natural gas,
on a BOE basis. Enerplus' 2010 average daily production was comprised of 31,135 bbls/day of crude oil, 3,889 bbls/day of NGLs and 288.7 MMcf/day of natural gas for a total of
83,139 BOE/day, a decrease of approximately 8,430 BOE/day compared to 2009 average daily production of 32,984 bbls/day of crude oil, 4,157 bbls/day of NGLs and
326.6 MMcf/day of natural gas, for a total of 91,569 BOE/day. The decline in average daily production in 2010 is largely attributable to lower capital spending in 2009 and the sale of
10,400 BOE/day of non-core production. Enerplus exited 2010 with average daily production of approximately 77,200 BOE/day. Approximately 72% of Enerplus' 2010 production was
operated by Enerplus and the remaining 28% was operated by industry partners. As at December 31, 2010, the oil and natural gas property interests held by Enerplus were estimated to
contain proved plus probable reserves of 110,893 Mbbls of light and medium crude oil, 38,960 Mbbls of heavy crude oil, 11,576 Mbbls of NGLs, 752,187 MMcf of natural gas and
116,662 MMcf of shale gas, for a total of 306,237 MBOE. Enerplus' proved reserves represented approximately 72% of total proved plus probable reserves, and approximately 53% of Enerplus'
proved plus probable reserves were weighted to crude oil and NGLs. See "Oil and Natural Gas Reserves".

ENERPLUS2010 ANNUAL INFORMATION
FORM5

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SUMMARY OF PRINCIPAL PRODUCTION LOCATIONS

LOGO

The
following table outlines Enerplus' reserves as at December 31, 2010 and its average daily production in 2010, in each case on a company interest basis, for Enerplus' five resource
plays and its other conventional oil and natural gas properties. Enerplus' former oil sands properties did not have any production in 2010.

|Play Type              |  | Proved
Reserves |  | Probable
Reserves |  | Proved Plus
Probable
Reserves |  | Average Daily
Production | 
|---------------------- |  | --------------- |  | ----------------- |  | ----------------------------- |  | ------------------------ | 
|                      
|                       |  | (MMBOE)         |  | (MMBOE)           |  | (MMBOE)                       |  | (BOE/day)                | 
|Crude Oil              |  |                 |  |                   |  |                               |  |                          | 
|Bakken/Tight Oil       |  | 38.0            |  | 19.5              |  | 57.5                          |  | 11,305                   | 
|Crude Oil Waterfloods  |  | 65.2            |  | 18.5              |  | 83.7                          |  | 14,688                   | 
|Other Conventional Oil |  | 20.8            |  | 6.9               |  | 27.7                          |  | 8,535                    | 
|                      
|Total Crude Oil        |  | 124.0           |  | 44.9              |  | 168.9                         |  | 34,528                   | 
|                      
|                       |  | (BcfGE)         |  | (BcfGE)           |  | (BcfGE)                       |  | (McfGE/day)              | 
|Natural Gas            |  |                 |  |                   |  |                               |  |                          | 
|Marcellus Shale Gas    |  | 52.4            |  | 64.8              |  | 117.2                         |  | 9,338                    | 
|Tight Gas              |  | 228.7           |  | 92.1              |  | 320.8                         |  | 85,084                   | 
|Shallow Gas            |  | 164.8           |  | 55.7              |  | 220.5                         |  | 117,598                  | 
|Other Conventional Gas |  | 126.3           |  | 38.7              |  | 165.0                         |  | 79,649                   | 
|                      
|Total Natural Gas      |  | 572.2           |  | 251.4             |  | 823.5                         |  | 291,669                  | 
|                      
|                       |  |                 |  |                   |  |                               |  |                          | 
|                      
|Total                  |  | 219.4 MMBOE     |  | 86.8 MMBOE        |  | 306.2 MMBOE                   |  | 83,139 BOE/day           | 
|                      

6      ENERPLUS2010 ANNUAL INFORMATION
FORM

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During the year ended December 31, 2010, on a BOE basis, approximately 58% of Enerplus' production was derived from Alberta, 16% from
Saskatchewan, 11% from Montana, 8% from British Columbia, 2% from each of North Dakota, Pennsylvania and Manitoba and minimal amounts from other jurisdictions such as Utah, Wyoming and West Virginia.
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, 2010. All
properties listed in the table (other than "Other") are located in Alberta unless otherwise noted.

2010 Average Daily Production from Principal Properties

|                                    |  |                      |  | Product   
|----------------------------------- |  | -------------------- |  | ----------
|                                    |  |                      |  | Crude Oil 
|Property                            |  | Primary Play Type    |  | Heavy     
|                                    |  |                     
|                                    |  |                      |  | (bbls/day)
|Sleeping Giant, Montana, U.S.A.     |  | Bakken/Tight Oil     |  |          
|Shackleton, Saskatchewan            |  | Shallow Gas          |  |          
|Tommy Lakes, British Columbia       |  | Tight Gas            |  |          
|Brooks                              |  | Other Conventional   |  | 2,346     
|Bantry                              |  | Shallow Gas          |  |          
|Medicine Hat Glauconitic "C" Unit   |  | Crude Oil Waterflood |  | 2,491     
|Pembina 5 Way                       |  | Crude Oil Waterflood |  |          
|Verger                              |  | Shallow Gas          |  |          
|Fort Berthold, North Dakota, U.S.A. |  | Bakken/Tight Oil     |  |          
|Joarcam                             |  | Crude Oil Waterflood |  |          
|Marcellus, Eastern U.S.A.           |  | Shale Gas            |  |          
|Pine Creek                          |  | Tight Gas            |  |          
|Giltedge                            |  | Crude Oil Waterflood |  | 1,502     
|Hanna Garden                        |  | Shallow Gas          |  |          
|Elmworth                            |  | Tight Gas            |  |          
|Virden, Manitoba                    |  | Crude Oil Waterflood |  |          
|Burnt Timber                        |  | Tight Gas            |  |          
|Chinchaga                           |  | Other Conventional   |  |          
|Medicine Hat South                  |  | Shallow Gas          |  |          
|Hanlan-Robb                         |  | Other Conventional   |  |          
|Saskatchewan Oil Ratcliffe          |  | Crude Oil Waterflood |  |          
|Sylvan Lake                         |  | Other Conventional   |  |          
|Other                               |  | N/A                  |  | 1,734     
|                                    |  |                     
|TOTAL                               |  |                      |  | 8,073     
|                                    |  |                     

CAPITAL EXPENDITURES AND COSTS INCURRED

In 2010, Enerplus invested approximately $542.7 million through its capital program, net of $18.3 million in drilling royalty credits provided by
the Province of Alberta ("DRCs"), which was approximately 81% higher than its capital program in 2009. Enerplus invested approximately
$457.4 million on development expenditures and $85.3 million on plants and facilities. The foregoing does not include approximately $1.018 billion of expenditures made on property
and asset acquisitions in 2010.

ENERPLUS2010 ANNUAL INFORMATION
FORM7

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The
following table outlines the development capital expenditures made by Enerplus in 2010 with respect to each of its five resource plays and other conventional oil and natural gas properties, net of
$18.3 million in DRCs, as well as Enerplus' former Kirby oil sands project.

|Play Type              |  | 2010 Development
Capital Spending | 
|---------------------- |  | --------------------------------- | 
|                      
|                       |  | ($ millions)                      | 
|Crude Oil              |  |                                   | 
|Bakken/Tight Oil       |  | 172.1                             | 
|Crude Oil Waterfloods  |  | 126.9                             | 
|Other Conventional Oil |  | 21.4                              | 
|Oil Sands              |  | 0.2                               | 
|                      
|Total Crude Oil        |  | 320.6                             | 
|                      
|Natural Gas            |  |                                   | 
|Marcellus Shale Gas    |  | 122.8                             | 
|Tight Gas              |  | 65.0                              | 
|Shallow Gas            |  | 26.3                              | 
|Other Conventional Gas |  | 8.0                               | 
|                      
|Total Natural Gas      |  | 222.1                             | 
|                      
|Total                  |  | 542.7                             | 
|                      

In the financial year ended December 31, 2010, Enerplus made the following expenditures in the categories noted, as prescribed by
NI 51-101:

|              |  | Property Acquisition Costs |  | Exploration |     | Development | 
|------------- |  | -------------------------- |  | ----------- | --- | ----------- | 
|              |  | Proved                     |  | Unproved    |     | Costs       | 
|              |  |                           
|              |  | ($ in millions)           
|Canada        |  | 25.0                       |  | 133.0       |     | 58.0        | 
|United States |  | 77.0                       |  | 690.7       | (1) | 74.8        | 
|              |  |                           
|Total         |  | 102.0                      |  | 823.7       |     | 132.8       | 
|              |  |                           

Note:

Enerplus expects its 2011 development capital spending to be approximately $650 million, with 65% projected to be invested in oil projects. Enerplus
expects to focus approximately 85% of its 2011 development capital on its Bakken/Tight Oil, Crude Oil Waterflood and Marcellus resource plays. With continued low natural gas prices, the majority of
Enerplus' natural gas spending is planned for its Marcellus interests to further delineate the resource and preserve Enerplus' lease positions. The foregoing plans do not include any potential
acquisition activity or large undeveloped land purchases. Enerplus will review its 2011 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 2011 spending will be evenly distributed throughout the year given the nature and location of
the spending.

For
information regarding Enerplus' planned 2011 development capital expenditures for each of its resource plays and its other conventional oil and natural gas assets, see
"Enerplus' Resource Play Types".

8      ENERPLUS2010 ANNUAL INFORMATION
FORM

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EXPLORATION AND DEVELOPMENT ACTIVITIES

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,
2010, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

|                        |  | Canada            |  | United States    
|----------------------- |  | ----------------- |  | -----------------
|                        |  | Development Wells |  | Exploratory Wells
|Category of Well        |  | Gross             |  | Net              
|                        |  |                  
|Crude oil wells         |  | 129               |  | 61.8             
|Natural gas wells       |  | 169               |  | 133.8            
|Service wells           |  | 29                |  | 0.7              
|Dry and abandoned wells |  | 1                 |  | 0.6              
|                        |  |                  
|Total                   |  | 328               |  | 176.9            
|                        |  |                  

For a description of Enerplus' planned 2011 development plans and the anticipated sources of funding those plans, see
"Capital Expenditures and Costs Incurred" above and "Enerplus' Resource
Play Types" below.

OIL AND NATURAL GAS WELLS AND UNPROVED PROPERTIES

The following table summarizes, as at December 31, 2010, Enerplus' interests in producing wells and in non-producing wells which were
not producing but which may be capable of production, along with Enerplus' interests in unproved properties (as defined in NI 51-101). Although many wells produce both oil
and natural gas, a well is categorized as an oil well or a natural gas well based upon the proportion of oil or natural gas production that constitutes the majority of production from
that well.

|                 |  | Producing Wells |  | Non-Producing Wells |  | Unproved
Properties
(thousands of acres)
|---------------- |  | --------------- |  | ------------------- |  | ----------------------------------------
|                 |  | Oil             |  | Natural Gas         |  | Oil                                     
|                 |  | Gross           |  | Net                 |  | Gross                                   
|                 |  |                 |  |                    
|Alberta          |  | 1,788           |  | 884.1               |  | 6,778                                   
|Saskatchewan     |  | 2,507           |  | 500.2               |  | 2,538                                   
|British Columbia |  |                |  |                    |  | 235                                     
|Manitoba         |  | 503             |  | 275.5               |  |                                        
|Montana          |  | 243             |  | 141.4               |  | 1                                       
|North Dakota     |  | 40              |  | 24.5                |  | 1                                       
|Pennsylvania     |  |                |  |                    |  | 48                                      
|Maryland         |  |                |  |                    |  |                                        
|West Virginia    |  |                |  |                    |  | 13                                      
|Utah             |  | 2               |  | 1.8                 |  |                                        
|Colorado         |  |                |  |                    |  |                                        
|                 |  |                 |  |                    
|Total            |  | 5,083           |  | 1,827.5             |  | 9,614                                   
|                 |  |                 |  |                    

Enerplus expects its rights to explore, develop and exploit on approximately 99,000 net acres of unproved properties to expire prior to
December 31, 2011 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.

ENERPLUS2010 ANNUAL INFORMATION
FORM9

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ENERPLUS' RESOURCE PLAY TYPES

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

Bakken/Tight Oil

Overview

Enerplus' Bakken/Tight Oil resource play includes properties in Montana, North Dakota and southeastern 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. 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° API) and some associated natural gas.
Enerplus' Bakken/Tight Oil resource play represented approximately 14% of its 2010 average daily production on a BOE basis, with the majority of this production coming from Enerplus'
U.S. Bakken properties. Approximately 19% of Enerplus' proved plus probable reserves as at December 31, 2010 were attributable to the Bakken/Tight Oil resource play. These
properties are predominantly operated by Enerplus.

Enerplus'
Bakken/Tight Oil resource play grew significantly in 2010 through the acquisition of undeveloped acreage in North Dakota and Saskatchewan. Enerplus added to its North Dakota Bakken position
with the acquisition of 58,921 net acres for an aggregate purchase price of $588 million, which also included production of 1,900 BOE/day. Enerplus also purchased
104,500 net acres of prospective land contiguous to its existing holds in the Freda Lake, Neptune and Oungre areas of Saskatchewan for $118.7 million. Enerplus now holds over
220,000 net acres of undeveloped land that is prospective for the Bakken and the Three Forks formations in certain areas. Total production from this resource play grew by 12%
year-over-year with the increase in production coming primarily from drilling activity in North Dakota.

In
2010, the majority of Enerplus' drilling activity occurred in its U.S. Bakken assets where Enerplus drilled 6.4 net horizontal wells at the Sleeping Giant field and another
14.8 net horizontal wells at the Fort Berthold, North Dakota property. Drilling results to date at the Fort Berthold area have generally exceeded Enerplus' expectations, and are the basis for
the increase in capital spending planned for the area in 2011. Enerplus also drilled a number of wells in Saskatchewan targeting the Bakken formation on both its operated leases and through its
non-operated working interest at Taylorton. The drilling results on Enerplus' operated leases have been disappointing and while oil was discovered in this area, the limited quantity does
not meet current economic thresholds. Enerplus is continuing to evaluate seismic data from the area to assess the potential of the Bakken and other zones.

Enerplus
expects to spend approximately $300 million, representing approximately one-half of its 2011 capital budget, on its Bakken/Tight Oil properties. Based upon the success of
the drilling activities in Fort Berthold, approximately $230 million has been targeted for this area as Enerplus moves into the development phase. Enerplus plans to drill 32 net operated
wells at Fort Berthold with at least 75% of these wells planned as long lateral horizontal wells. The primary target will be the Bakken formation, however Enerplus also plans to test the Three Forks
formation underlying the Bakken to evaluate the potential and future prospectivity of this zone. Enerplus has secured service agreements for frac crews, proppant and a drilling rig to support the
successful execution of its program. Enerplus is also working to have midstream agreements in place by mid-year 2011 that will allow it to tie in its production and capture the associated
natural gas. The remaining $70 million planned to be spent on Bakken/Tight Oil properties is planned to be invested at Sleeping Giant in Montana and in Enerplus' Canadian tight
oil properties.

Enerplus
expects that production at Fort Berthold will more than double as Enerplus exits 2011, with total production from Enerplus' Bakken/Tight Oil resource play growing by 50% throughout 2011,
exiting in the range of 18,000 to 21,000 BOE/day. Given the high initial productivity of the wells drilled on these properties and the competition for services in this region, exit production
volumes and capital spending could vary from guidance depending upon when new wells are drilled, completed and tied in.

Contingent Resource Estimate

An internal evaluation of Enerplus' Bakken zone leases at the Fort Berthold, North Dakota property conducted by Enerplus and audited by McDaniel has attributed
a "best estimate" of 60 MMBOE of contingent resources attributable to the Bakken formation only, effective as of December 31, 2010. This evaluation assumes and includes approximately
90 future drilling locations based upon a land utilization rate of 85%, using a combination of short and long lateral wells with a range of recoveries from 250,000 to 800,000 bbls of
crude oil from each well. Enerplus expects that 65% of the wells drilled will be long lateral wells. This evaluation does not include any additional volumes that may be recovered from the Three Forks
formation, which Enerplus believes is prospective across its entire North Dakota acreage. For additional

10      ENERPLUS2010 ANNUAL INFORMATION
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information
on the disclosure of contingent resources, including with respect to the presentation of the "best estimate" of contingent resources, see "Presentation of Enerplus'
Oil and Gas Reserves, Resources and Production Information  Disclosure of Contingent Resources".

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 Fort Berthold, North Dakota properties as reserves consist of additional
delineation drilling to establish economic productivity in the development areas and limitations to development based on adverse topography or other surface restrictions. Significant positive factors
related to the estimate include continued advancement of drilling and completion technology and early performance of producing wells is above forecast. A significant negative factor related to the
estimate is the limited performance history in the immediate area of the contingent resource. There are a number of inherent risks and contingencies associated with the development of the acquired
interests in the property including commodity price fluctuations, project costs, Enerplus' ability to make the necessary capital expenditures to develop the properties, reliance on industry partners
in project development, 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.

Marcellus Shale Gas

Overview

Enerplus made its initial strategic investment in the Marcellus shale gas fairway in 2009, gaining entry into one of the largest shale gas plays in North
America. In 2010 Enerplus continued to add to its Marcellus interests through the acquisition of operated interests in Pennsylvania, West Virginia and Maryland. Through four transactions totaling
$169.3 million, Enerplus acquired 75,317 net acres of land, 70,833 of which it will operate. For additional information, see "General Development of the
Business  Developments in the Past Three Years". At December 31, 2010, Enerplus had a 23% average working interest in
565,000 gross acres (approximately 130,000 net acres) in the Marcellus play, as well as a 90% working interest representing approximately 70,000 net acres, taking Enerplus' total
interests in the Marcellus play to approximately 200,000 net acres. The majority of Enerplus' non-operated leases are concentrated in Pennsylvania with additional acreage located in
West Virginia and Maryland. The majority of Enerplus' operated acreage is located in West Virginia and Maryland with additional leases in Centre and Clinton Counties in Pennsylvania. Much of the
non-operated acreage is contiguous and the majority of the leases allow extensions of the primary term for an additional five years. Enerplus' operated acreage has longer lease tenures of
approximately seven years.

The
majority of Enerplus' activity in the Marcellus play in 2010 was with its primary operating partner, Chief Oil & Gas LLC, with whom Enerplus participated in the drilling of
60 gross wells (11.7 net wells) during the year. Enerplus also participated in another 62 gross wells (1.9 net wells) during 2010 with other operators. Enerplus planned to
have 67 gross wells tied-in during 2010. However, due to the timing of pipeline infrastructure and the availability of frac crews, only 38 gross wells were tied in during the
year. Despite these delays, Enerplus exited 2010 on track with average daily gross production of approximately 91 MMcf/day of natural gas (18 MMcf/day net to Enerplus), as well results
exceeded Enerplus' original expectations. Enerplus estimates that there is currently 120 to 140 MMcf/day of natural gas production waiting on completion or tie-in, of which
Enerplus' average working interest is approximately 20%. Enerplus also began drilling its first operated well in Centre County in 2010. The well was completed in January 2011 but Enerplus does
not expect tie-in until late 2011 due to current infrastructure and gathering limitations.

Enerplus
has planned for approximately $160 million of capital expenditures for the Marcellus play in 2011, plus an additional $116 million to be expended as part of the Marcellus Carry
Amount, with the majority of all expenditures being spent on Enerplus' non-operated interests. With its joint venture partners, Enerplus plans to have eight to ten rigs working throughout
the play in 2011 and expects to drill 150 gross wells (22.4 net wells). Enerplus also expects to complete approximately 121 wells and plans to have 94 new wells on stream
by the end of the year. Enerplus also plans to drill five gross operated delineation wells (four net wells) on its new Marcellus leases. Due to the timing of infrastructure, access to frac crews and
permitting, Enerplus estimates the cycle time from commencement of drilling to production tie-in is approximately nine months. As a result of this timeframe, Enerplus anticipates that
close to 75% of the wells that it plans to drill in 2011 will not be tied-in until 2012. As well, with the high activity levels in this region, well costs could come under pressure
throughout the year. Despite these delays, Enerplus expects production in 2011 to grow by approximately 150% to approximately 45 MMcf/day of natural gas by year-end 2011.

As
of December 31, 2010, Enerplus' remaining commitment under the Marcellus Carry Amount was approximately US$147 million. Under the terms of the Marcellus JDA, which only applies to the
initial lands in which Enerplus acquired an interest in September 2009, until the full Marcellus Carry Amount has been spent by Enerplus, the operators of the subject properties have the sole
right to propose the drilling and development of wells on these 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 operator has failed to conduct sufficient drilling

ENERPLUS2010 ANNUAL INFORMATION
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activities
as set out in the Marcellus JDA), and the operations on the subject 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 operators, in addition to other remedies available to the operators,
Enerplus will be required to reassign to the operators 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 operators will have the right to suspend some or all of their 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 certain area of mutual interest
provisions, as described below. Following Enerplus' expenditure of the required Marcellus Carry Amount, either of Enerplus or the operator 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 with the vendors of Enerplus' interests in the Marcellus properties acquired in 2009 that will provide Enerplus the opportunity to
partner with the vendors in any follow-on acquisitions or swaps in the Marcellus region. These provisions 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, processing and compression of Enerplus' share of production from its Marcellus properties. These agreements
are intended to provide Enerplus with cost certainty and direct ties to the northeastern United States natural gas markets through connections with major interstate pipelines.

The
independent Haas Report has assigned 52.4 BcfGE of proved reserves and 117.2 BcfGE of proved plus probable Reserves to Enerplus' interests in its Marcellus properties as of
December 31, 2010. This represents an increase of 370% from the independent estimate of the proved plus probable reserves conducted by Haas at December 31, 2009.

Contingent Resource Estimate

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 3.9 TcfGE at December 31, 2010. This represents an 86% increase over the December 31, 2009 best
estimate of contingent resources associated with the Marcellus of 2.1 TcfGE. This estimate assumes a land utilization rate of 64% and that the average well would produce approximately
4 Bcf per well. Enerplus expects recoveries to
average approximately 30% with an average well density of four to eight 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.

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 its Marcellus interests 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, and other issues related to gas development in populated areas. There are a number of inherent risks and contingencies associated with the development of Enerplus' 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 on the disclosure of contingent resources, including with respect to the presentation of the "best estimate" of contingent resources, see
"Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information  Disclosure of Contingent
Resources".

12      ENERPLUS2010 ANNUAL INFORMATION
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Crude Oil Waterfloods

Overview

Enerplus' Crude Oil Waterflood assets are a core part of its business contributing low decline, stable production and cash flow to support investment in
Enerplus' new growth plays. This portfolio includes a variety of properties producing from formations such as the Cardium, Viking, Ratcliffe, Lloydminster and Glauconitic that offer new drilling
opportunities, optimization and enhanced oil recovery potential. Through horizontal drilling technology and reservoir depletion analysis, Enerplus has identified new opportunities in a number of these
mature fields that it believes will help offset declines and, in some areas, provide a modest level of growth.

In
a 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
2010, Enerplus' five largest Crude Oil 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 85% 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, 2010 and approximately 27% of Enerplus' proved plus probable reserves as at December 31, 2010 were
related to its crude oil waterflood assets.

Enerplus'
activities in 2010 in this play were focused on drilling and recompletion activities and facility upgrades. Nine horizontal wells were drilled into the Freda Ratcliffe unit and Enerplus
expects that there are an additional 16 drilling locations in this unit. As a result of land acquisitions completed in 2010, Enerplus will be reviewing the potential from other formations on
these new lands on the Ratcliffe trend and believes that there are significant additional development opportunities. Enerplus also began work on its first polymer pilot project at Giltedge, which will
continue through 2011. Approximately 53% of Enerplus' Crude Oil Waterflood capital spending in 2010 was directed towards drilling both producing and injector wells, including completion activities.

Enerplus
expects to spend approximately $110 million on its Crude Oil Waterflood assets in 2011 and to maintain production volumes throughout the year at approximately 14,000 BOE/day.
Enerplus intends to also continue to advance the work on its enhanced oil recovery pilot projects. A significant portion of this capital is being directed to activities that Enerplus believes will
position it for future production and reserve growth.

Contingent Resource Estimate

Enerplus has conducted an internal evaluation of the contingent resources associated with its Crude Oil Waterflood projects, which has resulted in a "best
estimate" of 60.5 MMBOE being classified as contingent resources effective as of December 31, 2010. Incremental oil recovery from seven existing waterfloods through optimization work
accounts for approximately 26.2 MMBOE of the total. The remaining 34.3 MMBOE is attributable to enhanced oil recovery ("EOR") projects in
Enerplus' Giltedge property and the Medicine Hat Glauconitic "C" Unit where projects are underway. Although further EOR projects are being developed for other of Enerplus' waterflood properties, these
have not been thoroughly evaluated and are not classified as contingent resources.

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". Significant positive
factors embedded in this estimate include well-established waterflood technology and a long history of waterflood performance data. The EOR estimates are based on incremental recovery from
higher displacement efficiency without any improvement in areal sweep. A significant negative factor relevant to this estimate is the geological complexity and its effect on injector producer
connectivity. The contingency preventing these resources from being classified as reserves is the early stage of implementation to the specific waterfloods. There are a number of inherent risks and
contingencies associated with the development of these properties including 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 on the disclosure of contingent resources, including with respect to the presentation of the "best estimate" of contingent resources, see
"Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information  Disclosure of Contingent
Resources".

ENERPLUS2010 ANNUAL INFORMATION
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Tight Gas

Enerplus' Tight Gas resource play represented 17% of Enerplus' average daily production in 2010 and 17% of its proved plus probable reserves as at
December 31, 2010. Enerplus' highest producing tight natural gas properties in 2010 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 the Mannville, Nikannassin, Montney, Bluesky, Nordegg and Halfway zones, as well as
others. Enerplus added to its land position in the Deep Basin region of northwestern Alberta and northeastern British Columbia in 2010 and now has approximately 80,000 net acres of undeveloped
land which it believes is prospective for the Montney and Mannville formations.

Capital
spending on Enerplus' Tight Gas properties was reduced in 2010 to $65 million due to weakening natural gas prices and low economic returns. Enerplus expects to spend approximately
$60 million on its Tight Gas assets in 2011 and will focus on drilling four horizontal wells at Tommy Lakes and a limited number of delineation wells in the Mannville zone in order to determine
the future potential of its undeveloped Mannville acreage.

Shallow Gas

Enerplus' Shallow Gas resource play represented approximately 24% of Enerplus' average daily production volumes in 2010 and approximately 12% of Enerplus'
proved plus probable reserves as at December 31, 2010. Approximately 85% of Enerplus' shallow natural gas production is operated by Enerplus. In 2010, Enerplus' five largest Shallow 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.

Due
to weakening gas prices Enerplus dramatically reduced its capital spending on its Shallow Gas assets in 2010 investing $26 million, net of approximately $18.3 million in Alberta
drilling royalty credits. Most of the spending was at the Shackleton field in Saskatchewan and at Bantry, Verger and Hanna Garden in Alberta. Drilling activity was focused on shallow natural gas
properties in Alberta to take advantage of the Alberta royalty drilling incentive program. In total, Enerplus drilled 103.7 net shallow natural gas wells, virtually all of which attracted
drilling royalty credits.

With
the current natural gas price outlook, Enerplus' projected shallow natural gas capital spending for 2011 has been reduced to approximately $10 million. Activities will be focused on
recompleting wells at Shackleton, Saskatchewan targeting multiple productive zones.

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. During 2010, Enerplus sold
approximately 10,400 BOE/day of conventional oil and natural gas production in order to better focus and improve its operations. Development capital expended on those properties in 2010 was
reduced to approximately $30 million, given Enerplus' desire to concentrate its capital spending and efforts in its core resource play areas. Enerplus plans to spend approximately
$10 million of capital on its other conventional oil and gas properties in 2011.

Production
from these other conventional oil and natural gas properties represented approximately 26% of Enerplus' average daily production in 2010 and declined to 20% of Enerplus'
2010 December exit volumes as a result of asset sales during the year. These properties also accounted for approximately 18% of Enerplus' estimated total proved plus probable reserves as of
December 31, 2010.

Major
facilities included in Enerplus' conventional oil and natural gas properties include a 100% interest in Brooks North and South oil batteries and water disposal facilities, a 75% interest
in the Colgate oil battery and an 8% interest in the Hanlan-Robb gas plant.

EQUITY INVESTMENTS

In 2005, Enerplus formed a joint venture with Laricina, a private oil sands company focused on SAGD development in the Athabasca oil sands fairway. 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, 2010, Enerplus owned approximately
4.3 million shares of Laricina, representing approximately 8% of the total outstanding shares 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.

Enerplus
also has minor equity interests in several other resource focused entities with a book carrying value of approximately $26 million at December 31, 2010.

14      ENERPLUS2010 ANNUAL INFORMATION
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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 2010 and for the entire year,
separately for production in Canada and the United States, and in total.

|                                |  | Year Ended December 31, 2010
|------------------------------- |  | ----------------------------
|Country and Product Type        |  | First
Quarter               
|                                |  |                             
|Canada                          |  |                             
|Light and medium oil (bbls/day) |  | 14,812                      
|Heavy oil (bbls/day)            |  | 9,124                       
|                                |  |                             
|Total crude oil (bbls/day)      |  | 23,936                      
|Natural gas liquids (bbls/day)  |  | 3,925                       
|                                |  |                             
|Total liquids (bbls/day)        |  | 27,861                      
|Natural gas (Mcf/day)           |  | 283,460                     
|                                |  |                             
|Total Canada (BOE/day)          |  | 75,105                      
|                                |  |                             
|United States                   |  |                             
|Light and medium oil (bbls/day) |  | 7,038                       
|Heavy oil (bbls/day)            |  |                            
|                                |  |                             
|Total crude oil (bbls/day)      |  | 7,038                       
|Natural gas liquids (bbls/day)  |  |                            
|                                |  |                             
|Total liquids (bbls/day)        |  | 7,038                       
|Natural gas (Mcf/day)           |  | 15,460                      
|                                |  |                             
|Total United States (BOE/day)   |  | 9,614                       
|                                |  |                             
|Total Enerplus                  |  |                             
|Light and medium oil (bbls/day) |  | 21,850                      
|Heavy oil (bbls/day)            |  | 9,124                       
|                                |  |                             
|Total crude oil (bbls/day)      |  | 30,974                      
|Natural gas liquids (bbls/day)  |  | 3,925                       
|                                |  |                             
|Total liquids (bbls/day)        |  | 34,899                      
|Natural gas (Mcf/day)           |  | 298,920                     
|                                |  |                             
|Total Enerplus (BOE/day)        |  | 84,719                      
|                                |  |                             

ENERPLUS2010 ANNUAL INFORMATION
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QUARTERLY NETBACK HISTORY

The following tables set forth Enerplus' average netbacks received for each fiscal quarter in 2010 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 as those costs have been attributed to the applicable wells' principal product type.

|                                      |  | Year Ended December 31, 2010
|------------------------------------- |  | ----------------------------
|Light and Medium Crude Oil($ per bbl) |  |                             
|                                      |  |                             
|Canada                                |  |                             
|Sales price(1)                        |  | $                           
|Royalties                             |  |                             
|Production costs(2)                   |  |                             
|                                      |  |                             
|Netback                               |  | $                           
|                                      |  |                             
|United States                         |  |                             
|Sales price(1)                        |  | $                           
|Royalties(3)                          |  |                             
|Production costs(2)                   |  |                             
|                                      |  |                             
|Netback                               |  | $                           
|                                      |  |                             
|Total Enerplus                        |  |                             
|Sales price(1)                        |  | $                           
|Royalties(3)                          |  |                             
|Production costs(2)                   |  |                             
|                                      |  |                             
|Netback                               |  | $                           
|                                      |  |                             

|
|

|                      |  | Year Ended December 31, 2010
|--------------------- |  | ----------------------------
|Heavy Oil($ per bbl)  |  |                             
|                      |  |                             
|Canada/Total Enerplus |  |                             
|Sales price(1)        |  | $                           
|Royalties             |  |                             
|Production costs(2)   |  |                             
|                      |  |                             
|Netback               |  | $                           
|                      |  |                             

|
|

|                               |  | Year Ended December 31, 2010
|------------------------------ |  | ----------------------------
|Natural Gas Liquids($ per bbl) |  |                             
|                               |  |                             
|Canada/Total Enerplus          |  |                             
|Sales price(1)                 |  | $                           
|Royalties                      |  |                             
|Production costs(2)            |  |                             
|                               |  |                             
|Netback                        |  | $                           
|                               |  |                             

16      ENERPLUS2010 ANNUAL INFORMATION
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|
|

|                       |  | Year Ended December 31, 2010
|---------------------- |  | ----------------------------
|Natural Gas($ per Mcf) |  |                             
|                       |  |                             
|Canada                 |  |                             
|Sales price(1)         |  | $                           
|Royalties              |  |                             
|Production costs(2)    |  |                             
|                       |  |                             
|Netback                |  | $                           
|                       |  |                             
|United States          |  |                             
|Sales price(1)         |  | $                           
|Royalties(3)           |  |                             
|Production costs(2)    |  |                             
|                       |  |                             
|Netback                |  | $                           
|                       |  |                             
|Total Enerplus         |  |                             
|Sales price(1)         |  | $                           
|Royalties(3)           |  |                             
|Production costs(2)    |  |                             
|                       |  |                             
|Netback                |  | $                           
|                       |  |                             

|
|

|                          |  | Year Ended December 31, 2010
|------------------------- |  | ----------------------------
|Total Enerplus($ per BOE) |  |                             
|                          |  |                             
|Canada                    |  |                             
|Sales price(1)            |  | $                           
|Royalties                 |  |                             
|Production costs(2)       |  |                             
|                          |  |                             
|Netback                   |  | $                           
|                          |  |                             
|United States             |  |                             
|Sales price(1)            |  | $                           
|Royalties(3)              |  |                             
|Production costs(2)       |  |                             
|                          |  |                             
|Netback                   |  | $                           
|                          |  |                             
|Total Enerplus            |  |                             
|Sales price(1)            |  | $                           
|Royalties(3)              |  |                             
|Production costs(2)       |  |                             
|                          |  |                             
|Netback                   |  | $                           
|                          |  |                             

Notes:

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

ENERPLUS2010 ANNUAL INFORMATION
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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 $590 million on an undiscounted basis and $114 million discounted at 10%. The calculations of future net revenue under "Oil and Natural Gas
Reserves" in this Annual Information Form exclude approximately $238 million on an undiscounted basis and $29 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 $59 million on an undiscounted basis and $52 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

TAX HORIZON

Under Enerplus' previous structure as an income trust prior to the Conversion, taxable income of the Fund's Canadian operating subsidiaries was transferred
through interest, royalty and other distribution payments to the Fund which, in turn, allocated all of its taxable income to its unitholders. Accordingly, no material cash Canadian income taxes were
paid by the Fund or its Canadian operating subsidiaries for the year ended December 31, 2010.

As
described in further detail under "General Development of the Business  Conversion from an Income Trust to a
Corporation", effective January 1, 2011, pursuant to the Conversion, Enerplus' business was reorganized from an income trust structure to a Canadian corporate
structure and as a result Enerplus is subject to normal Canadian corporate income taxation. 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, the amount of tax pools available and the tax laws governing the amount and timing
of deductions.

Within
the context of current commodity prices and capital spending plans, Enerplus generally does not expect to be taxable prior to 2013, with nominal U.S. cash taxes anticipated to be paid
in 2012. This estimate may vary depending on numerous factors, including fluctuations in commodity prices and the 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 10% of cash flow. 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, overall commodity prices and governing tax laws. See "Risk Factors  Changes in tax and other laws may
adversely affect Enerplus and its shareholders."

For
additional information, see Notes 2(g) and 12 to Enerplus' audited consolidated financial statements for the year ended December 31, 2010 and the information under the
heading "Taxes" in Enerplus' MD&A for the year ended December 31, 2010.

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 $72.91/bbl for its light and medium crude oil, $63.17/bbl for its heavy crude oil and $51.41/bbl for its NGLs for the year ended December 31, 2010,
compared to $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. Enerplus has contracted
transportation for 1,000 bbls/day of its Bakken oil production beginning in May 2011 for five years, and an additional 5,000 bbls/day commencing January 1, 2013 for
five years.

18      ENERPLUS2010 ANNUAL INFORMATION
FORM

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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 84% of its natural gas split evenly between the daily and monthly AECO market indices and 16% against monthly U.S.-based indices.

Enerplus'
percentage of 2010 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 33% compared to 38% in 2009. The
average price received by Enerplus (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2010 was $4.05/Mcf compared to $3.91/Mcf for
the year ended December 31, 2009.

Enerplus
has contracted to transport approximately 200 MMcf/day of natural gas in Canada with contracts that range anywhere from one month to five years. Enerplus has contracted gas
gathering capacity for its Marcellus production of 6,000 MMbtu per day, which increases to 13,650 MMbtu per day on June 1, 2011 until March 31, 2022. In
addition, transportation for Enerplus' Marcellus sales gas has been contracted on Columbia Gas Transmission for 4,500 MMbtu per day until January 2014.

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 13
to Enerplus' audited consolidated financial statements for the year ended December 31, 2010 and under the headings "Results of
Operations  Pricing" and "Results of Operations  Price Risk
Management" in Enerplus' MD&A for the year ended December 31, 2010, each of which is available through the internet on the Corporation's website at
www.enerplus.com, on the Corporation's SEDAR profile at www.sedar.com and on the Corporation's EDGAR profile
at www.sec.gov.

ENERPLUS2010 ANNUAL INFORMATION
FORM19

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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 86% of the net present value (discounted at 10%, using forecast prices and costs) of
Enerplus' proved plus probable oil and natural gas reserves located in Canada and 96% of such value of Enerplus' reserves located in the western United States. Enerplus has evaluated the
balance of these 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.

Haas,
independent petroleum consultants based in Dallas, Texas, has 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, 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 Haas Report to Canadian dollar amounts for presentation in this Annual Information Form.

The
following sections and tables summarize, as at December 31, 2010, Enerplus' oil, NGLs, natural gas and shale gas reserves and the estimated net present values of future net revenues
associated with such reserves, together with certain information, estimates and assumptions associated with such reserve estimates. The data contained in the tables is a summary of the evaluations,
and as a result the tables may contain slightly different numbers than the evaluations themselves due to rounding. Additionally, the numbers in the tables may not add due to rounding. For information
relating to the changes in the volumes of Enerplus' reserves from December 31, 2009 to December 31, 2010, 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. For additional information, see "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.

The
following tables set forth the estimated volumes and net present value of future net revenue attributable to Enerplus' reserves at December 31, 2010, using both forecast and constant price
and cost cases.

20      ENERPLUS2010 ANNUAL INFORMATION
FORM

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Summary of Oil and Gas Reserves
As of December 31, 2010Forecast Prices and Costs

|                               |               | OIL AND NATURAL GAS RESERVES
|------------------------------ | ------------- | ----------------------------
|                               |               | Light & Medium Oil          
|RESERVES CATEGORY              |               | Company Interest            
|                               |               |                             
|                               |               | (Mbbls)                     
|Proved Developed Producing     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Developed Non-Producing |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Undeveloped             |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved                   |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Probable                       |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved Plus Probable     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             

(continues on next page)

ENERPLUS2010 ANNUAL INFORMATION
FORM21

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|
|

Summary of Oil and Gas Reserves
As of December 31, 2010Forecast Prices and Costs(continued)

|                               |               | OIL AND NATURAL GAS RESERVES
|------------------------------ | ------------- | ----------------------------
|                               |               | Natural Gas                 
|RESERVES CATEGORY              |               | Company Interest            
|                               |               |                             
|                               |               | (MMcf)                      
|Proved Developed Producing     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Developed Non-Producing |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Undeveloped             |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved                   |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Probable                       |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved Plus Probable     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             

22      ENERPLUS2010 ANNUAL INFORMATION
FORM

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Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves
As of December 31, 2010Forecast Prices and Costs

|                               |               | NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR) |        |                              |      
|------------------------------ | ------------- | -------------------------------------------------------------- | ------ | ---------------------------- | -----
|                               |               | Before Deducting Income Taxes                                  |        | After Deducting Income Taxes |      
|RESERVES CATEGORY              |               | 0%                                                             |        | 5%                           |      
|                               |               |                                                                |        |                             
|                               |               | (in $ millions)                                                |        | ($/BOE)                      |      
|Proved developed producing     |               |                                                                |        |                              |      
|                               | Canada        |                                                                | 4,831  |                              | 3,168
|                               | United States |                                                                | 1,539  |                              | 1,062
|                               |               |                                                                |        |                             
|                               | Total         |                                                                | 6,370  |                              | 4,230
|                               |               |                                                                |        |                             
|Proved developed non-producing |               |                                                                |        |                              |      
|                               | Canada        |                                                                | 91     |                              | 67   
|                               | United States |                                                                | 67     |                              | 49   
|                               |               |                                                                |        |                             
|                               | Total         |                                                                | 158    |                              | 116  
|                               |               |                                                                |        |                             
|Proved undeveloped             |               |                                                                |        |                              |      
|                               | Canada        |                                                                | 289    |                              | 183  
|                               | United States |                                                                | 465    |                              | 273  
|                               |               |                                                                |        |                             
|                               | Total         |                                                                | 754    |                              | 456  
|                               |               |                                                                |        |                             
|Total Proved                   |               |                                                                |        |                              |      
|                               | Canada        |                                                                | 5,211  |                              | 3,418
|                               | United States |                                                                | 2,071  |                              | 1,384
|                               |               |                                                                |        |                             
|                               | Total         |                                                                | 7,282  |                              | 4,802
|                               |               |                                                                |        |                             
|Probable                       |               |                                                                |        |                              |      
|                               | Canada        |                                                                | 2,291  |                              | 1,073
|                               | United States |                                                                | 1,649  |                              | 858  
|                               |               |                                                                |        |                             
|                               | Total         |                                                                | 3,940  |                              | 1,931
|                               |               |                                                                |        |                             
|Total Proved Plus Probable     |               |                                                                |        |                              |      
|                               | Canada        |                                                                | 7,502  |                              | 4,491
|                               | United States |                                                                | 3,720  |                              | 2,242
|                               |               |                                                                |        |                             
|                               | Total         |                                                                | 11,222 |                              | 6,733
|                               |               |                                                                |        |                             

Note:

ENERPLUS2010 ANNUAL INFORMATION
FORM23

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|
|

Summary of Oil and Gas Reserves
As of December 31, 2010Constant Prices and Costs

|                               |               | OIL AND NATURAL GAS RESERVES
|------------------------------ | ------------- | ----------------------------
|                               |               | Light & Medium Oil          
|RESERVES CATEGORY              |               | Company Interest            
|                               |               |                             
|                               |               | (Mbbls)                     
|Proved Developed Producing     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Developed Non-Producing |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Undeveloped             |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved                   |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Probable                       |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved Plus Probable     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             

(continues on next page)

24      ENERPLUS2010 ANNUAL INFORMATION
FORM

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|
|

Summary of Oil and Gas Reserves
As of December 31, 2010Constant Prices and Costs
(continued)

|                               |               | OIL AND NATURAL GAS RESERVES
|------------------------------ | ------------- | ----------------------------
|                               |               | Natural Gas                 
|RESERVES CATEGORY              |               | Company Interest            
|                               |               |                             
|                               |               | (MMcf)                      
|Proved Developed Producing     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Developed Non-Producing |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Proved Undeveloped             |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved                   |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Probable                       |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             
|Total Proved Plus Probable     |               |                             
|                               | Canada        |                             
|                               | United States |                             
|                               |               |                             
|                               | Total         |                             
|                               |               |                             

ENERPLUS2010 ANNUAL INFORMATION
FORM25

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Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves
As of December 31, 2010Constant Prices and Costs

|                               |               | NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/YEAR) |       |                              |      
|------------------------------ | ------------- | -------------------------------------------------------------- | ----- | ---------------------------- | -----
|                               |               | Before Deducting Income Taxes                                  |       | After Deducting Income Taxes |      
|RESERVES CATEGORY              |               | 0%                                                             |       | 5%                           |      
|                               |               |                                                                |       |                             
|                               |               | (in $ millions)                                                |       | ($/BOE)                      |      
|Proved Developed Producing     |               |                                                                |       |                              |      
|                               | Canada        |                                                                | 3,185 |                              | 2,248
|                               | United States |                                                                | 1,056 |                              | 795  
|                               |               |                                                                |       |                             
|                               | Total         |                                                                | 4,241 |                              | 3,043
|                               |               |                                                                |       |                             
|Proved Developed Non-Producing |               |                                                                |       |                              |      
|                               | Canada        |                                                                | 62    |                              | 47   
|                               | United States |                                                                | 46    |                              | 36   
|                               |               |                                                                |       |                             
|                               | Total         |                                                                | 108   |                              | 83   
|                               |               |                                                                |       |                             
|Proved Undeveloped             |               |                                                                |       |                              |      
|                               | Canada        |                                                                | 172   |                              | 111  
|                               | United States |                                                                | 261   |                              | 159  
|                               |               |                                                                |       |                             
|                               | Total         |                                                                | 433   |                              | 270  
|                               |               |                                                                |       |                             
|Total Proved                   |               |                                                                |       |                              |      
|                               | Canada        |                                                                | 3,419 |                              | 2,406
|                               | United States |                                                                | 1,363 |                              | 990  
|                               |               |                                                                |       |                             
|                               | Total         |                                                                | 4,782 |                              | 3,396
|                               |               |                                                                |       |                             
|Probable                       |               |                                                                |       |                              |      
|                               | Canada        |                                                                | 1,251 |                              | 645  
|                               | United States |                                                                | 929   |                              | 537  
|                               |               |                                                                |       |                             
|                               | Total         |                                                                | 2,180 |                              | 1,182
|                               |               |                                                                |       |                             
|Total Proved Plus Probable     |               |                                                                |       |                              |      
|                               | Canada        |                                                                | 4,670 |                              | 3,051
|                               | United States |                                                                | 2,292 |                              | 1,527
|                               |               |                                                                |       |                             
|                               | Total         |                                                                | 6,962 |                              | 4,578
|                               |               |                                                                |       |                             

Note:

26      ENERPLUS2010 ANNUAL INFORMATION
FORM

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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, 2011 (and utilized by Haas for consistency in Enerplus'
reserves reporting) and the following inflation and exchange rate assumptions:

|           |  | CRUDE OIL |     | NATURAL GAS       |     | NATURAL GAS LIQUIDS |     |                       |     |                         |    
|---------- |  | --------- | --- | ----------------- | --- | ------------------- | --- | --------------------- | --- | ----------------------- | ---
|           |  |           |     |                   |     |                     |     |                       |     |                         |    
|Year       |  | WTI(1)    |     | Edmonton Light(2) |     | Alberta Heavy(3)    |     | Sask Cromer Medium(4) |     | Alberta
AECO
Spot Price |    
|           |  |           |     |                   |     |                    
|           |  | ($US/bbl) |     | ($Cdn/bbl)        |     | ($Cdn/bbl)          |     | ($Cdn/bbl)            |     | ($Cdn/MMbtu)            |    
|2011       |  | 85.00     |     | 84.20             |     | 66.70               |     | 77.20                 |     | 4.25                    |    
|2012       |  | 87.70     |     | 88.40             |     | 68.70               |     | 80.40                 |     | 4.90                    |    
|2013       |  | 90.50     |     | 91.80             |     | 68.60               |     | 82.50                 |     | 5.40                    |    
|2014       |  | 93.40     |     | 94.80             |     | 70.80               |     | 85.20                 |     | 5.90                    |    
|2015       |  | 96.30     |     | 97.70             |     | 73.00               |     | 87.90                 |     | 6.35                    |    
|Thereafter |  |           | (5) |                   | (5) |                     | (5) |                       | (5) |                         | (5)
|           |  |           |     |                   |     |                    

Notes:

In 2010, Enerplus received a weighted average price (net of transportation costs but before hedging) of $63.17/bbl for heavy crude oil, $72.91/bbl for
light and medium crude oil, $51.41/bbl for NGLs and $4.05/Mcf for natural gas.

CONSTANT PRICES AND COSTS

The constant price and cost case is based upon an unweighted arithmetic average of the first-day-of-the-month
price for the applicable commodity for each of the twelve months preceding the company's fiscal year-end as at December 31, 2010, held constant throughout the estimated lives
of the properties to which the estimate applies, and assumes the continuance of operating costs projected for 2011 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, 2010 and the following exchange rate assumptions:

|         |  | CRUDE OIL |  | NATURAL GAS       |  | NATURAL GAS LIQUIDS |  |                       |  |                         | 
|-------- |  | --------- |  | ----------------- |  | ------------------- |  | --------------------- |  | ----------------------- | 
|         |  |           |  |                   |  |                     |  |                       |  |                         | 
|Year     |  | WTI(1)    |  | Edmonton Light(2) |  | Alberta Heavy(3)    |  | Sask Cromer Medium(4) |  | Alberta
AECO
Spot Price | 
|         |  |           |  |                   |  |                    
|         |  | ($US/bbl) |  | ($Cdn/bbl)        |  | ($Cdn/bbl)          |  | ($Cdn/bbl)            |  | ($Cdn/MMbtu)            | 
|Constant |  | 79.43     |  | 78.70             |  | 68.41               |  | 75.04                 |  | 4.03                    | 
|         |  |           |  |                   |  |                    

Notes:

ENERPLUS2010 ANNUAL INFORMATION
FORM27

---



UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2010, using forecast prices and costs, is set forth below
(columns or rows may not add due to rounding):

|Reserves Category             |               | Revenue         |        | Royalties
and
Production
Taxes |       | Operating
Costs |       | Develop-
ment
Costs |     | Abandon-
ment
and
Reclamation
Costs |     | Future Net
Revenue
Before
Income
Taxes |        | Income
Taxes |       | Future Net
Revenue
After
Income
Taxes |      
|----------------------------- | ------------- | --------------- | ------ | ------------------------------ | ----- | --------------- | ----- | ------------------- | --- | ----------------------------------- | --- | -------------------------------------- | ------ | ------------ | ----- | ------------------------------------- | -----
|                             
|                              |               | (in $ millions)
|Proved Reserves               |               |                 |        |                                |       |                 |       |                     |     |                                     |     |                                        |        |              |       |                                       |      
|                              | Canada        |                 | 11,563 |                                | 1,758 |                 | 3,812 |                     | 472 |                                     | 311 |                                        | 5,211  |              | 893   |                                       | 4,318
|                              | United States |                 | 3,955  |                                | 1,013 |                 | 674   |                     | 187 |                                     | 10  |                                        | 2,071  |              | 770   |                                       | 1,301
|                             
|                              | Total         |                 | 15,518 |                                | 2,771 |                 | 4,486 |                     | 659 |                                     | 321 |                                        | 7,282  |              | 1,663 |                                       | 5,619
|                             
|Proved Plus Probable Reserves |               |                 |        |                                |       |                 |       |                     |     |                                     |     |                                        |        |              |       |                                       |      
|                              | Canada        |                 | 15,997 |                                | 2,486 |                 | 5,091 |                     | 578 |                                     | 341 |                                        | 7,502  |              | 1,497 |                                       | 6,005
|                              | United States |                 | 6,719  |                                | 1,725 |                 | 973   |                     | 289 |                                     | 12  |                                        | 3,720  |              | 1,477 |                                       | 2,244
|                             
|                              | Total         |                 | 22,716 |                                | 4,211 |                 | 6,064 |                     | 867 |                                     | 353 |                                        | 11,222 |              | 2,974 |                                       | 8,249
|                             

28      ENERPLUS2010 ANNUAL INFORMATION
FORM

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NET PRESENT VALUE OF FUTURE NET REVENUE BY RESERVES CATEGORY AND PRODUCTION GROUP

The net present value of future net revenue before income taxes by reserves category and production group as of December 31, 2010, using forecast
prices and costs and discounted at 10% per year, is set forth below:

|Reserves Category             |  | Production Group              |  | Net Present Value of
Future Net Revenue
Before Income Taxes
(Discounted at 10%/year) |  | Unit Value(3) | 
|----------------------------- |  | ----------------------------- |  | ------------------------------------------------------------------------------------ |  | ------------- | 
|                             
|                              |  |                               |  | (in $ millions)                                                                      |  | ($/Bbl/$/Mcf) | 
|Canada                        |  |                               |  |                                                                                      |  |               | 
|Proved Reserves               |  | Light and Medium Crude Oil(1) |  | 1,126                                                                                |  | $26.10/Bbl    | 
|                              |  | Heavy Oil(1)                  |  | 664                                                                                  |  | $27.72/Bbl    | 
|                              |  | Natural Gas(2)                |  | 779                                                                                  |  | $1.96/Mcf     | 
|                              |  | Shale Gas(2)                  |  | n/a                                                                                  |  | n/a           | 
|                              |  |                               |  |                                                                                      | 
|                              |  | Total                         |  | 2,569                                                                                |  |               | 
|                             
|Proved Plus Probable Reserves |  | Light and Medium Crude Oil(1) |  | 1,374                                                                                |  | $24.99/Bbl    | 
|                              |  | Heavy Oil(1)                  |  | 808                                                                                  |  | $25.38/Bbl    | 
|                              |  | Natural Gas(2)                |  | 1,029                                                                                |  | $1.91/Mcf     | 
|                              |  | Shale Gas(2)                  |  | n/a                                                                                  |  | n/a           | 
|                              |  |                               |  |                                                                                      | 
|                              |  | Total                         |  | 3,211                                                                                |  |               | 
|                             
|United States                 |  |                               |  |                                                                                      |  |               | 
|Proved Reserves               |  | Light and Medium Crude Oil(1) |  | 914                                                                                  |  | $36.33/Bbl    | 
|                              |  | Heavy Oil(1)                  |  | n/a                                                                                  |  | n/a           | 
|                              |  | Natural Gas(2)                |  | 26                                                                                   |  | $4.07/Mcf     | 
|                              |  | Shale Gas(2)                  |  | 100                                                                                  |  | $2.37/Mcf     | 
|                              |  |                               |  |                                                                                      | 
|                              |  | Total                         |  | 1,040                                                                                |  |               | 
|                             
|Proved Plus Probable Reserves |  | Light and Medium Crude Oil(1) |  | 1,317                                                                                |  | $34.50/Bbl    | 
|                              |  | Heavy Oil(1)                  |  | n/a                                                                                  |  | n/a           | 
|                              |  | Natural Gas(2)                |  | 48                                                                                   |  | $3.35/Mcf     | 
|                              |  | Shale Gas(2)                  |  | 214                                                                                  |  | $2.29/Mcf     | 
|                              |  |                               |  |                                                                                      | 
|                              |  | Total                         |  | 1,579                                                                                |  |               | 
|                             
|Total Enerplus                |  |                               |  |                                                                                      |  |               | 
|Proved Reserves               |  | Light and Medium Crude Oil(1) |  | 2,040                                                                                |  | $29.87/Bbl    | 
|                              |  | Heavy Oil(1)                  |  | 665                                                                                  |  | $27.72/Bbl    | 
|                              |  | Natural Gas(2)                |  | 804                                                                                  |  | $1.99/Mcf     | 
|                              |  | Shale Gas(2)                  |  | 100                                                                                  |  | $2.37/Mcf     | 
|                              |  |                               |  |                                                                                      | 
|                              |  | Total                         |  | 3,609                                                                                |  |               | 
|                             
|Proved Plus Probable Reserves |  | Light and Medium Crude Oil(1) |  | 2,691                                                                                |  | $28.89/Bbl    | 
|                              |  | Heavy Oil(1)                  |  | 808                                                                                  |  | $25.38/Bbl    | 
|                              |  | Natural Gas(2)                |  | 1,077                                                                                |  | $1.95/Mcf     | 
|                              |  | Shale Gas(2)                  |  | 214                                                                                  |  | $2.29/Mcf     | 
|                              |  |                               |  |                                                                                      | 
|                              |  | Total                         |  | 4,790                                                                                |  |               | 
|                             

Notes:

ENERPLUS2010 ANNUAL INFORMATION
FORM29

---



ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

The volume of production estimated for 2011 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 aggregated from estimates provided by McDaniel and Haas. Columns may not add due to rounding.

|                    |                            | Gross Proved Reserves              
|------------------- | -------------------------- | -----------------------------------
|                    |                            | Canada                             
|Product Type        |                            | Estimated 2011
Aggregate
Production
|                    |                            |                                    
|Crude Oil           |                            |                                    
|                    | Light and Medium Crude Oil |                                    
|                    | Heavy Oil                  |                                    
|                    |                            |                                    
|Total Crude Oil     |                            | 7,512                              
|Natural Gas Liquids |                            | 1,051                              
|                    |                            |                                    
|Total Liquids       |                            | 8,563                              
|Natural Gas         |                            | 74,036                             
|Shale Gas           |                            |                                   
|                    |                            |                                    
|Total               |                            | 20,902                             
|                    |                            |                                    

|
|

|                    |                            | Gross Probable Reserves            
|------------------- | -------------------------- | -----------------------------------
|                    |                            | Canada                             
|Product Type        |                            | Estimated 2011
Aggregate
Production
|                    |                            |                                    
|Crude Oil           |                            |                                    
|                    | Light and Medium Crude Oil |                                    
|                    | Heavy Oil                  |                                    
|                    |                            |                                    
|Total Crude Oil     |                            | 338                                
|Natural Gas Liquids |                            | 47                                 
|                    |                            |                                    
|Total Liquids       |                            | 385                                
|Natural Gas         |                            | 2,852                              
|Shale Gas           |                            |                                   
|                    |                            |                                    
|Total               |                            | 860                                
|                    |                            |                                    

30      ENERPLUS2010 ANNUAL INFORMATION
FORM

---



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 Common Shares 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".

|          |  | CANADA          |  | UNITED STATES                
|--------- |  | --------------- |  | -----------------------------
|          |  | Proved Reserves |  | Proved Plus
Probable Reserves
|Year      |  | Undiscounted    |  | Discounted
at 10%/year       
|          |  |                
|          |  | (in $ millions)
|2011      |  | 176             |  | 168                          
|2012      |  | 112             |  | 97                           
|2013      |  | 50              |  | 40                           
|2014      |  | 46              |  | 33                           
|2015      |  | 9               |  | 6                            
|Remainder |  | 79              |  | 30                           
|          |  |                
|Total     |  | 472             |  | 374                          
|          |  |                

RECONCILIATION OF RESERVES

Overview

Enerplus' total proved plus probable reserves, on a company interest basis, at December 31, 2010 were 306.2 MMBOE, down approximately 11%
from year-end 2009, with approximately 60% of this decline attributable to the sale of non-core properties, net of acquisitions. Approximately 34.0 MMBOE of proved plus
probable reserves were sold during 2010, of which 23.4 MMBOE were attributable to crude oil properties and 63.9 BcfGE were related to natural gas properties. Approximately
11.8 MMBOE of proved plus probable reserves were acquired in 2010, primarily in Enerplus' Fort Berthold, North Dakota Bakken oil property. The majority of Enerplus' acquisitions in 2010 were of
undeveloped land with nominal proved or probable reserves.

Enerplus'
development capital spending replaced 114% of 2010 production, before reserves revisions. 34.7 MMBOE of proved plus probable reserves were added from Enerplus' delineation and
development activities, comprised of 16.8 MMBOE from its oil properties and 107.0 BcfGE from its natural gas properties. The majority of the additions were attributable to Enerplus'
North Dakota Bakken and Marcellus resource plays, with additions of 11.0 MMBOE and 87.6 BcfGE, respectively. Enerplus also added 5.7 MMBOE of oil in Canada across various
properties, including its Crude Oil Waterflood properties, and 9.0 BcfGE of gas from Enerplus' Deep Tight Gas plays.

A
decrease in the outlook for natural gas prices and underperformance in a few properties resulted in negative revisions to Enerplus' natural gas properties of 108.5 BcfGE of proved plus
probable reserves and 2.6 MMBOE of proved plus probable reserves associated with Enerplus' oil properties, for a total of 20.7 MMBOE of proved plus probable reserves. The majority of the
negative revisions were associated with Enerplus' shallow gas assets. Approximately 40%, or 45 BcfGE, of Enerplus' natural gas revisions related to the decline in natural gas price forecasts,
while 63.5 BcfGE related to performance mainly in its Shackleton Shallow Gas property where well interference changed Enerplus' view on long term performance and economics. The net present
value of the performance revisions at Shackleton, discounted at 10%, was approximately $100 million or 2% of Enerplus' 2010 year-end proved plus probable reserves value discounted at
10%. Approximately 567 natural gas locations were removed from Enerplus' reserve report along with approximately $95.6 million of associated future development capital. Of the total
20.7 MMBOE in revisions, 6.9 MMBOE, or roughly one-third, were in the proved reserves category. After these revisions, approximately 150 shallow gas drilling locations
associated with Enerplus' Shackleton property remain in its reserve report.

The
following tables reconcile Enerplus' oil and natural gas reserves (on both a company interest and a gross reserves basis) from December 31, 2009 to December 31, 2010,
by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

ENERPLUS2010 ANNUAL INFORMATION
FORM31

---



Reconciliation of Company Interest Reserves

Canadian Oil and Gas Reserves

|CANADA                           |  | Light & Medium Oil |   | Heavy Oil |   | Natural Gas Liquids 
|-------------------------------- |  | ------------------ | - | --------- | - | --------------------
|Factors                          |  | Proved             |   | Probable  |   | Proved
Plus
Probable
|                                 |  |                    |   |          
|                                 |  | (Mbbls)            |   | (Mbbls)   |   | (Mbbls)             
|December 31, 2009                |  | 61,053             |   | 16,776    |   | 77,829              
|Acquisitions                     |  | 249                |   | 56        |   | 305                 
|Dispositions                     |  | (11,001            | ) | (4,060    | ) | (15,061             
|Discoveries                      |  |                   |   |          |   |                    
|Extensions and Improved Recovery |  | 3,505              |   | 1,699     |   | 5,204               
|Economic Factors                 |  | (86                | ) | (34       | ) | (120                
|Technical Revisions              |  | 866                |   | (339      | ) | 527                 
|Production                       |  | (4,978             | ) |          |   | (4,978              
|                                 |  |                    |   |          
|December 31, 2010                |  | 49,608             |   | 14,098    |   | 63,706              
|                                 |  |                    |   |          

|
|

|CANADA                           |  | Associated and
Non-Associated Gas
(Natural Gas) |   | Shale Gas |   | Total               
|-------------------------------- |  | ----------------------------------------------- | - | --------- | - | --------------------
|Factors                          |  | Proved                                          |   | Probable  |   | Proved
Plus
Probable
|                                 |  |                                                 |   |          
|                                 |  | (MMcf)                                          |   | (MMcf)    |   | (MMcf)              
|December 31, 2009                |  | 696,585                                         |   | 250,061   |   | 946,646             
|Acquisitions                     |  | 2,235                                           |   | (1,004    | ) | 1,231               
|Dispositions                     |  | (50,085                                         | ) | (17,930   | ) | (68,015             
|Discoveries                      |  |                                                |   |          |   |                    
|Extensions and Improved Recovery |  | 12,431                                          |   | 6,991     |   | 19,422              
|Economic Factors                 |  | (33,414                                         | ) | (15,150   | ) | (48,564             
|Technical Revisions              |  | (20,366                                         | ) | (48,985   | ) | (69,351             
|Production                       |  | (97,337                                         | ) |          |   | (97,337             
|                                 |  |                                                 |   |          
|December 31, 2010                |  | 510,049                                         |   | 173,983   |   | 684,032             
|                                 |  |                                                 |   |          

|
|

United States Oil and Gas Reserves

|UNITED STATES                    |  | Light & Medium Oil |   | Heavy Oil |   | Natural Gas Liquids 
|-------------------------------- |  | ------------------ | - | --------- | - | --------------------
|Factors                          |  | Proved             |   | Probable  |   | Proved
Plus
Probable
|                                 |  |                    |   |          
|                                 |  | (Mbbls)            |   | (Mbbls)   |   | (Mbbls)             
|December 31, 2009                |  | 25,452             |   | 7,287     |   | 32,739              
|Acquisitions                     |  | 4,799              |   | 5,890     |   | 10,689              
|Dispositions                     |  |                   |   |          |   |                    
|Discoveries                      |  |                   |   |          |   |                    
|Extensions and Improved Recovery |  | 6,379              |   | 4,129     |   | 10,508              
|Economic Factors                 |  | 40                 |   | 38        |   | 78                  
|Technical Revisions              |  | (2,329             | ) | (1,078    | ) | (3,407              
|Production                       |  | (3,420             | ) |          |   | (3,420              
|                                 |  |                    |   |          
|December 31, 2010                |  | 30,921             |   | 16,266    |   | 47,187              
|                                 |  |                    |   |          

(continues on next page)

32      ENERPLUS2010 ANNUAL INFORMATION
FORM

---



Reconciliation of Company Interest Reserves (continued)

|
|

|UNITED STATES                    |  | Associated and
Non-Associated Gas
(Natural Gas) |   | Shale Gas |  | Total                |   |       
|-------------------------------- |  | ----------------------------------------------- | - | --------- |  | -------------------- | - | ------
|Factors                          |  | Proved                                          |   | Probable  |  | Proved
Plus
Probable |   | Proved
|                                 |  |                                                 |   |          
|                                 |  | (MMcf)                                          |   | (MMcf)    |  | (MMcf)               |   | (MMcf)
|December 31, 2009                |  | 49,449                                          |   | 17,085    |  | 66,534               |   | 8,127 
|Acquisitions                     |  | 1,191                                           |   | 2,359     |  | 3,550                |   |      
|Dispositions                     |  |                                                |   |          |  |                     |   |      
|Discoveries                      |  |                                                |   |          |  |                     |   |      
|Extensions and Improved Recovery |  | 2,096                                           |   | 3,016     |  | 5,112                |   | 35,767
|Economic Factors                 |  | 12                                              |   | 33        |  | 45                   |   |      
|Technical Revisions              |  | (4,035                                          | ) | 1,621     |  | (2,414               | ) | 11,696
|Production                       |  | (4,672                                          | ) |          |  | (4,672               | ) | (3,365
|                                 |  |                                                 |   |          
|December 31, 2010                |  | 44,041                                          |   | 24,114    |  | 68,155               |   | 52,225
|                                 |  |                                                 |   |          

|
|

Total Oil and Gas Reserves

|TOTAL                            |  | Light & Medium Oil |   | Heavy Oil |   | Natural Gas Liquids  |   |        
|-------------------------------- |  | ------------------ | - | --------- | - | -------------------- | - | -------
|Factors                          |  | Proved             |   | Probable  |   | Proved
Plus
Probable |   | Proved 
|                                 |  |                    |   |          
|                                 |  | (Mbbls)            |   | (Mbbls)   |   | (Mbbls)              |   | (Mbbls)
|December 31, 2009                |  | 86,505             |   | 24,063    |   | 110,568              |   | 34,431 
|Acquisitions                     |  | 5,048              |   | 5,946     |   | 10,994               |   |       
|Dispositions                     |  | (11,001            | ) | (4,060    | ) | (15,061              | ) | (4,207 
|Discoveries                      |  |                   |   |          |   |                     |   |       
|Extensions and Improved Recovery |  | 9,884              |   | 5,828     |   | 15,712               |   | 15     
|Economic Factors                 |  | (46                | ) | 4         |   | (42                  | ) | (17    
|Technical Revisions              |  | (1,463             | ) | (1,417    | ) | (2,880               | ) | 1,902  
|Production                       |  | (8,398             | ) |          |   | (8,398               | ) | (2,947 
|                                 |  |                    |   |          
|December 31, 2010                |  | 80,529             |   | 30,364    |   | 110,893              |   | 29,177 
|                                 |  |                    |   |          

|
|

|TOTAL                            |  | Associated and
Non Associated Gas
(Natural Gas) |   | Shale Gas |   | Total                |   |       
|-------------------------------- |  | ----------------------------------------------- | - | --------- | - | -------------------- | - | ------
|Factors                          |  | Proved                                          |   | Probable  |   | Proved
Plus
Probable |   | Proved
|                                 |  |                                                 |   |          
|                                 |  | (MMcf)                                          |   | (MMcf)    |   | (MMcf)               |   | (MMcf)
|December 31, 2009                |  | 746,034                                         |   | 267,146   |   | 1,013,180            |   | 8,127 
|Acquisitions                     |  | 3,426                                           |   | 1,355     |   | 4,781                |   |      
|Dispositions                     |  | (50,085                                         | ) | (17,930   | ) | (68,015              | ) |      
|Discoveries                      |  |                                                |   |          |   |                     |   |      
|Extensions and Improved Recovery |  | 14,527                                          |   | 10,007    |   | 24,534               |   | 35,767
|Economic Factors                 |  | (33,402                                         | ) | (15,117   | ) | (48,519              | ) |      
|Technical Revisions              |  | (24,401                                         | ) | (47,364   | ) | (71,765              | ) | 11,696
|Production                       |  | (102,009                                        | ) |          |   | (102,009             | ) | (3,365
|                                 |  |                                                 |   |          
|December 31, 2010                |  | 554,090                                         |   | 198,097   |   | 752,187              |   | 52,225
|                                 |  |                                                 |   |          

ENERPLUS2010 ANNUAL INFORMATION
FORM33

---



Reconciliation of Gross Reserves

Canadian Oil and Gas Reserves

|CANADA                           |  | Light & Medium Oil |   | Heavy Oil |   | Natural Gas Liquids  |   |        
|-------------------------------- |  | ------------------ | - | --------- | - | -------------------- | - | -------
|Factors                          |  | Proved             |   | Probable  |   | Proved
Plus
Probable |   | Proved 
|                                 |  |                    |   |          
|                                 |  | (Mbbls)            |   | (Mbbls)   |   | (Mbbls)              |   | (Mbbls)
|December 31, 2009                |  | 60,393             |   | 16,551    |   | 76,944               |   | 34,401 
|Acquisitions                     |  | 249                |   | 56        |   | 305                  |   |       
|Dispositions                     |  | (10,889            | ) | (4,016    | ) | (14,905              | ) | (4,192 
|Discoveries                      |  |                   |   |          |   |                     |   |       
|Extensions and Improved Recovery |  | 3,544              |   | 1,719     |   | 5,263                |   | 15     
|Economic Factors                 |  | (86                | ) | (34       | ) | (120                 | ) | (17    
|Technical Revisions              |  | 720                |   | (341      | ) | 379                  |   | 1,886  
|Production                       |  | (4,863             | ) |          |   | (4,863               | ) | (2,930 
|                                 |  |                    |   |          
|December 31, 2010                |  | 49,068             |   | 13,935    |   | 63,003               |   | 29,163 
|                                 |  |                    |   |          

|CANADA                           |  | Associated
and Non-Associated Gas
(Natural Gas) |   | Shale Gas |   | Total                |   |       
|-------------------------------- |  | ----------------------------------------------- | - | --------- | - | -------------------- | - | ------
|Factors                          |  | Proved                                          |   | Probable  |   | Proved
Plus
Probable |   | Proved
|                                 |  |                                                 |   |          
|                                 |  | (MMcf)                                          |   | (MMcf)    |   | (MMcf)               |   | (MMcf)
|December 31, 2009                |  | 679,922                                         |   | 244,873   |   | 924,795              |   |      
|Acquisitions                     |  | 2,228                                           |   | (1,007    | ) | 1,221                |   |      
|Dispositions                     |  | (47,835                                         | ) | (17,258   | ) | (65,093              | ) |      
|Discoveries                      |  |                                                |   |          |   |                     |   |      
|Extensions and Improved Recovery |  | 11,783                                          |   | 5,140     |   | 16,923               |   |      
|Economic Factors                 |  | (33,414                                         | ) | (15,150   | ) | (48,564              | ) |      
|Technical Revisions              |  | (20,772                                         | ) | (46,205   | ) | (66,977              | ) |      
|Production                       |  | (94,367                                         | ) |          |   | (94,367              | ) |      
|                                 |  |                                                 |   |          
|December 31, 2010                |  | 497,545                                         |   | 170,393   |   | 667,938              |   |      
|                                 |  |                                                 |   |          

|
|

United States Oil and Gas Reserves

|UNITED STATES                    |  | Light & Medium Oil |   | Heavy Oil |   | Natural Gas Liquids  |   |        
|-------------------------------- |  | ------------------ | - | --------- | - | -------------------- | - | -------
|Factors                          |  | Proved             |   | Probable  |   | Proved
Plus
Probable |   | Proved 
|                                 |  |                    |   |          
|                                 |  | (Mbbls)            |   | (Mbbls)   |   | (Mbbls)              |   | (Mbbls)
|December 31, 2009                |  | 25,392             |   | 7,267     |   | 32,659               |   |       
|Acquisitions                     |  | 4,799              |   | 5,890     |   | 10,689               |   |       
|Dispositions                     |  |                   |   |          |   |                     |   |       
|Discoveries                      |  |                   |   |          |   |                     |   |       
|Extensions and Improved Recovery |  | 6,379              |   | 4,129     |   | 10,508               |   |       
|Economic Factors                 |  | 40                 |   | 38        |   | 78                   |   |       
|Technical Revisions              |  | (2,652             | ) | (1,143    | ) | (3,795               | ) |       
|Production                       |  | (3,336             | ) |          |   | (3,336               | ) |       
|                                 |  |                    |   |          
|December 31, 2010                |  | 30,622             |   | 16,181    |   | 46,803               |   |       
|                                 |  |                    |   |          

(continues on next page)

34      ENERPLUS2010 ANNUAL INFORMATION
FORM

---



Reconciliation of Gross Reserves (continued)

|
|

|UNITED STATES                    |  | Associated and
Non-Associated Gas
(Natural Gas) |   | Shale Gas |   | Total                |   |       
|-------------------------------- |  | ----------------------------------------------- | - | --------- | - | -------------------- | - | ------
|Factors                          |  | Proved                                          |   | Probable  |   | Proved
Plus
Probable |   | Proved
|                                 |  |                                                 |   |          
|                                 |  | (MMcf)                                          |   | (MMcf)    |   | (MMcf)               |   | (MMcf)
|December 31, 2009                |  | 35,687                                          |   | 13,137    |   | 48,824               |   | 8,127 
|Acquisitions                     |  | 1,191                                           |   | 2,359     |   | 3,550                |   |      
|Dispositions                     |  |                                                |   |          |   |                     |   |      
|Discoveries                      |  |                                                |   |          |   |                     |   |      
|Extensions and Improved Recovery |  | 1,596                                           |   | 1,916     |   | 3,512                |   | 35,767
|Economic Factors                 |  | 12                                              |   | 33        |   | 45                   |   |      
|Technical Revisions              |  | 2,277                                           |   | (1,535    | ) | 742                  |   | 11,696
|Production                       |  | (3,436                                          | ) |          |   | (3,436               | ) | (3,365
|                                 |  |                                                 |   |          
|December 31, 2010                |  | 37,327                                          |   | 15,910    |   | 53,237               |   | 52,225
|                                 |  |                                                 |   |          

|
|

Total Oil and Gas Reserves

|TOTAL                            |  | Light & Medium Oil |   | Heavy Oil |   | Natural Gas Liquids  |   |        
|-------------------------------- |  | ------------------ | - | --------- | - | -------------------- | - | -------
|Factors                          |  | Proved             |   | Probable  |   | Proved
Plus
Probable |   | Proved 
|                                 |  |                    |   |          
|                                 |  | (Mbbls)            |   | (Mbbls)   |   | (Mbbls)              |   | (Mbbls)
|December 31, 2009                |  | 85,785             |   | 23,818    |   | 109,603              |   | 34,401 
|Acquisitions                     |  | 5,048              |   | 5,946     |   | 10,994               |   |       
|Dispositions                     |  | (10,889            | ) | (4,016    | ) | (14,905              | ) | (4,192 
|Discoveries                      |  |                   |   |          |   |                     |   |       
|Extensions and Improved Recovery |  | 9,923              |   | 5,848     |   | 15,771               |   | 15     
|Economic Factors                 |  | (46                | ) | 4         |   | (42                  | ) | (17    
|Technical Revisions              |  | (1,932             | ) | (1,484    | ) | (3,416               | ) | 1,886  
|Production                       |  | (8,199             | ) |          |   | (8,199               | ) | (2,930 
|                                 |  |                    |   |          
|December 31, 2010                |  | 79,690             |   | 30,116    |   | 109,806              |   | 29,163 
|                                 |  |                    |   |          

|
|

|TOTAL                            |  | Associated and
Non-Associated Gas
(Natural Gas) |   | Shale Gas |   | Total                |   |       
|-------------------------------- |  | ----------------------------------------------- | - | --------- | - | -------------------- | - | ------
|Factors                          |  | Proved                                          |   | Probable  |   | Proved
Plus
Probable |   | Proved
|                                 |  |                                                 |   |          
|                                 |  | (MMcf)                                          |   | (MMcf)    |   | (MMcf)               |   | (MMcf)
|December 31, 2009                |  | 715,609                                         |   | 258,010   |   | 973,619              |   | 8,127 
|Acquisitions                     |  | 3,419                                           |   | 1,352     |   | 4,771                |   |      
|Dispositions                     |  | (47,835                                         | ) | (17,258   | ) | (65,093              | ) |      
|Discoveries                      |  |                                                |   |          |   |                     |   |      
|Extensions and Improved Recovery |  | 13,379                                          |   | 7,056     |   | 20,435               |   | 35,767
|Economic Factors                 |  | (33,402                                         | ) | (15,117   | ) | (48,519              | ) |      
|Technical Revisions              |  | (18,495                                         | ) | (47,740   | ) | (66,235              | ) | 11,696
|Production                       |  | (97,803                                         | ) |          |   | (97,803              | ) | (3,365
|                                 |  |                                                 |   |          
|December 31, 2010                |  | 534,872                                         |   | 186,303   |   | 721,175              |   | 52,225
|                                 |  |                                                 |   |          

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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

|                        |  | Crude Oil |  |                |  |         |  |         |  |             |  |           | 
|----------------------- |  | --------- |  | -------------- |  | ------- |  | ------- |  | ----------- |  | --------- | 
|Year(1)                 |  | Heavy     |  | Light &
Medium |  | Bitumen |  | NGLs    |  | Natural
Gas |  | Shale
Gas | 
|                        |  |           |  |                | 
|                        |  | (Mbbls)   |  | (Mbbls)        |  | (Mbbls) |  | (Mbbls) |  | (Bcf)       |  | (Bcf)     | 
|Aggregate Prior to 2008 |  | 4,937     |  | 12,714         |  | 9,308   |  | 1,639   |  | 251         |  |          | 
|2008                    |  | 1,100     |  | 3,496          |  |        |  | 173     |  | 14          |  |          | 
|2009                    |  | 812       |  | 2,133          |  |        |  | 17      |  | 4           |  | 5         | 
|2010                    |  |          |  | 6,674          |  |        |  | 66      |  | 4           |  | 11        | 
|                        |  |           |  |                | 

Probable Undeveloped Reserves

|                        |  | Crude Oil |  |                |  |         |  |         |  |             |  |           | 
|----------------------- |  | --------- |  | -------------- |  | ------- |  | ------- |  | ----------- |  | --------- | 
|Year(1)                 |  | Heavy     |  | Light &
Medium |  | Bitumen |  | NGLs    |  | Natural
Gas |  | Shale
Gas | 
|                        |  |           |  |                | 
|                        |  | (Mbbls)   |  | (Mbbls)        |  | (Mbbls) |  | (Mbbls) |  | (Bcf)       |  | (Bcf)     | 
|Aggregate Prior to 2008 |  | 1,172     |  | 7,057          |  | 58,746  |  | 662     |  | 134         |  |          | 
|2008                    |  | 665       |  | 1,246          |  |        |  | 169     |  | 11          |  |          | 
|2009                    |  | 779       |  | 527            |  |        |  | 52      |  | 6           |  | 14        | 
|2010                    |  |          |  | 3,322          |  |        |  | 103     |  | 3           |  | 46        | 
|                        |  |           |  |                | 

Note:

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 9.4 MMBOE of proved plus probable reserves which are capable of production but which, as of December 31, 2010,
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.

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Supplemental Operational Information

HEALTH, SAFETY AND ENVIRONMENT

Enerplus strives to develop and operate its oil and gas assets in a socially responsible manner and places a high priority on preserving the quality of the
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 in
an effort to support continuous improvement.

Health and Safety

In 2010, the number of Enerplus' employee health and safety incidents increased slightly compared to 2009, and Enerplus' 2010 employee safety performance was
below the Canadian Association of Petroleum Producers ("CAPP") 2009 industry average. Enerplus' 2010 employee recordable injury frequency rate was
0.41 injuries per 200,000 man hours compared to 0.38 injuries per 200,000 man hours in 2009. Enerplus' contractor total recordable injury frequency increased from
1.10 injuries per 200,000 man hours in 2009 to a rate of 1.72 injuries in 2010. An employee of a drilling contractor was fatally injured at an Enerplus work site in 2010.

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:

Enerplus
continues to develop and implement 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 monitors its compliance with all
regulations. In particular, Enerplus engages in the following activities:

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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. In 2010, this cost was approximately $130,000. In British Columbia, Enerplus is subject to the carbon tax introduced in
mid-2008. The cost of this tax was approximately $764,500 in 2010. In addition, Enerplus is required to report greenhouse gas emissions to the government of British Columbia by
March 31, 2011 under theCap and Trade Act(British Columbia). Enerplus expects that the B.C. government will issue emission allowances to
emitters in 2012. Potential future costs are unknown until emission allowances are allocated, however Enerplus does not expect such compliance costs to be material at its current hydrocarbon
production levels. Moreover, until there is more certainty with respect to the federal greenhouse gas regulations, Enerplus is unable to estimate the future potential compliance costs, although at
this time Enerplus does not expect such costs to be material given its current hydrocarbon production levels and at the current price of carbon offsets in the marketplace of approximately $15 per
tonne of carbon dioxide equivalent. In the U.S., the federal Environmental Protection Agency has issued a final greenhouse gas tailoring rule that addresses greenhouse gas emissions from stationary
sources under the Clean Air Act permitting programs, however Enerplus does not expect this rule 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".

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 and regulatory updates and risks are reviewed regularly by the Safety & Social Responsibility Committee of the
Corporation's board of directors. 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.

Overall,
Enerplus strives to operate in a socially responsible manner and 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. Annually, Enerplus identifies key focus areas to support this commitment and sets forth strategic reduction
targets. Enerplus believes that by monitoring metrics, continuously identifying areas for improvement and implementing strategies, processes and procedures in those key focus areas, Enerplus can
reduce its environmental impact.

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. Enerplus currently purchases insurance to protect against
third party liability, property damage, business interruption, pollution and well control. In addition, liability coverage is also carried for the directors and officers of Enerplus.

PERSONNEL

As at December 31, 2010, Enerplus employed a total of 709 persons, including full-time benefit and payroll consultants.

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Description of Capital Structure

The authorized capital of the Corporation consists of an unlimited number of Common Shares and a number of preferred shares, issuable in series
("Preferred Shares"), which are limited to an amount equal to not more than one-quarter of the number of issued and outstanding Common
Shares at the time of the issuance of any such Preferred Shares. The following is a summary of the rights, privileges, restrictions and conditions attaching to the Common Shares and the Preferred
Shares. Copies of the Corporation's articles of amalgamation and bylaws were filed on the Corporation's SEDAR profile at www.sedar.com on January 5, 2011 and
on the Corporation's EDGAR profile at www.sec.gov on January 5, 2011.

COMMON SHARES

Holders of Common Shares are entitled to receive notice of and to attend all meetings of shareholders of the Corporation and to one vote at such meetings for
each Common Share held. The holders of the Common Shares are, at the discretion of the Corporation's board of directors and subject to applicable legal restrictions and subject to the rights,
privileges, restrictions and conditions attaching to any other class or series of shares of the Corporation, entitled to receive any dividends declared by the Corporation's board of directors on the
Common Shares and to share in the remaining property of the Corporation upon liquidation, dissolution or winding-up.

PREFERRED SHARES

The Preferred Shares may be issued from time to time in one or more series with such rights, restrictions, privileges, conditions and designations attached
thereto as shall be fixed from time to time by the Corporation's board of directors. Subject to the provisions of the ABCA, the Preferred Shares of each series shall rank in parity with the Preferred
Shares of every other series. The Preferred Shares shall be entitled to preference over the Common Shares and any other shares of the Corporation ranking junior to the said Preferred Shares with
respect to payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up of the
Corporation, whether voluntary or involuntary, to the extent fixed in the case of each respective series, and may also be given such other preferences over the Common Shares and any other shares of
the Corporation ranking junior to the said Preferred Shares as may be fixed in the case of each such series. There are no Preferred Shares outstanding as of the date of this Annual
Information Form.

SHAREHOLDER RIGHTS PLAN

Effective January 1, 2011, the Corporation adopted the Shareholder Rights Plan, which was approved by the Fund's unitholders concurrently with
their approval of the Conversion on December 9, 2010. The Fund previously had in place a unitholder rights plan agreement that was initially approved by 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
Shareholder Rights Plan must next be renewed and approved by the Corporation's shareholders at the annual general meeting to be held in 2013, failing which it will expire at such time. The Shareholder
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 Common Shares (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Common Shares, other than such acquiring
person or entity, shall be entitled to acquire Common Shares at a discounted price. The Shareholder Rights Plan is similar to other shareholder rights plans adopted in the energy sector. A copy of the
Shareholder Rights Plan was filed as a "Security holder document" on January 5, 2011 on the Corporation's SEDAR profile at www.sedar.com, was filed on the
Corporation's EDGAR profile at www.sec.gov on January 5, 2011, and is available on the Corporation's website at www.enerplus.com
under "Corporate Governance".

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SENIOR UNSECURED NOTES

Enerplus has issued the Senior Unsecured Notes, of which US$459 million and Cdn$40 million principal amount were outstanding at
December 31, 2010. The Senior Unsecured Notes were originally issued in the amounts of (i) US$175 million on June 19, 2002 (of which
US$140 million principal amount remained outstanding at December 31, 2010), (ii) US$54 million on October 1, 2003, and
(iii) US$225 million, US$40 million and $40 million on June 18, 2009. Certain terms of the Senior Unsecured Notes are summarized below:

|Issue Date      |  | Original
Principal |  | Remaining
Principal |  | Coupon
Rate |  | Interest
Payment Dates  |  | Maturity Date   |  | Term                                                                         | 
|--------------- |  | ------------------ |  | ------------------- |  | ----------- |  | ----------------------- |  | --------------- |  | ---------------------------------------------------------------------------- | 
|               
|June 18, 2009   |  | $40 million        |  | $40 million         |  | 6.37%       |  | June 18 and December 18 |  | June 18, 2015   |  | Bullet payment on maturity                                                   | 
|June 18, 2009   |  | US$40 million      |  | US$40 million       |  | 6.82%       |  | June 18 and December 18 |  | June 18, 2015   |  | Bullet payment on maturity                                                   | 
|June 18, 2009   |  | US$225 million     |  | 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      |  | 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     |  | US$140 million      |  | 6.62%       |  | June 19 and December 19 |  | June 19, 2014   |  | Principal payments required in equal instalments on June 19, 2011 to 2014    | 
|               

For additional information regarding the Senior Unsecured Notes, see Note 8 to Enerplus' audited consolidated financial statements for the year
ended December 31, 2010. See also "Material Contracts and Documents Affecting Securityholder Rights".

BANK CREDIT FACILITY

As of December 31, 2010, Enerplus had a $1.0 billion unsecured, covenant-based credit facility with a syndicate of financial institutions maturing
June 30, 2013. For a description of the Bank Credit Facility, see Note 8 to Enerplus' audited consolidated financial statements for the year ended December 31, 2010.
See also "Material Contracts and Documents Affecting Securityholder Rights".

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Dividends and Distributions

DIVIDEND POLICY AND HISTORY

The Corporation's board of directors is responsible for determining the dividend policy of the Corporation from time to time. As the Corporation is an ABCA
corporation, the dividend policy must comply with the requirements of the ABCA, including satisfying the solvency test applicable to ABCA corporations. The Corporation has currently established a
dividend policy of paying monthly dividends to holders of Common Shares, with the 10th day of each calendar month as a dividend record date and the 20th day of such months as the
corresponding dividend payment date. However, any decision to pay dividends on the Common Shares will be made by the Corporation's board of directors on the basis of the relevant conditions existing
at such future time, and there can be no guarantee that the Corporation will maintain its current dividend policy. Dividend amounts will likely vary, and there can be no assurance as to the level of
dividends that will be paid or that any dividends will be paid at all. See "Risk Factors  Dividends on the Corporation's Common Shares
are variable". Monthly cash dividends paid to U.S. resident shareholders are converted to U.S. dollars based upon the actual Canadian to U.S. dollar
exchange rate on the dividend payment date, and accordingly, shareholders that are not resident in Canada are subject to foreign exchange rate risk on such payments.

The
following cash distributions were paid by the Fund to its unitholders in 2008, 2009 and 2010 (as well as in January 2011 with respect to the Fund's final distribution record
date of December 31, 2010), and the following dividends have been paid or declared by the Corporation in February and March of 2011:

|Month of Record and Payment Date |  |   | 2011 |  |   | 2010 |  |   | 2009 |  |   | 2008 | 
|-------------------------------- |  | - | ---- |  | - | ---- |  | - | ---- |  | - | ---- | 
|                                
|January(1)                       |  | $ | 0.18 |  | $ | 0.18 |  | $ | 0.25 |  | $ | 0.42 | 
|February                         |  |   | 0.18 |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|March                            |  |   | 0.18 |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|April                            |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|May                              |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|June                             |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|July                             |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|August                           |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.42 | 
|September                        |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.47 | 
|October                          |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.47 | 
|November                         |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.38 | 
|December                         |  |   | N/A  |  |   | 0.18 |  |   | 0.18 |  |   | 0.38 | 
|                                

Note:

For the tax treatment of Enerplus' distributions paid to unitholders in 2010, and certain tax information relating to the dividends paid on the Common Shares,
for Canadian and U.S. federal income tax purposes, please refer to the Corporation's website at www.enerplus.com.

Shareholders
are advised to consult their tax advisors regarding questions relating to the tax treatment of dividends paid by the Corporation. For additional information on potential risks associated
with the taxation of dividends paid by Enerplus, see"Risk Factors".

DIVIDEND REINVESTMENT PLAN

The Corporation has in place a dividend reinvestment plan under which eligible Canadian-resident shareholders may elect to apply the dividends paid on their
Common Shares towards the purchase of additional Common Shares from treasury of the Corporation at a 5% discount to the ten day weighted average trading price of the Common Shares on the TSX
immediately prior to the applicable dividend payment date. For additional information on the Corporation's dividend reinvestment plan and to obtain copies of the documents related to the plan, see the
Corporation's website at www.enerplus.com under "Investor Information  Shareholder
Information".

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Industry Conditions

OVERVIEW

The oil and natural gas industry is subject to extensive controls and regulation governing its operations (including land tenure, exploration, development,
production, refining, transportation, marketing, remediation, abandonment and reclamation) imposed by legislation enacted by various levels of government. The oil and natural gas industry is also
subject to 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 82% of Enerplus' 2010
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 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.

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 the world price of oil. Crude oil exported from
Canada is subject to regulation by the National Energy Board (the "NEB") and the Government of Canada. Oil exports may be made pursuant to export
contracts with terms not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been
obtained from the 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 issuance 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 issuance 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.

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THE NORTH AMERICA FREE TRADE AGREEMENT

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 and each U.S. state has legislation and regulations which govern oil and gas holdings and
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. 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 and upon commencement of production, 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 Crown-owned lands in Canada and federal and state lands in the U.S. are determined by negotiations between the
freehold mineral owner and the lessee. Crown royalties in Canada and federal and state royalties and production taxes in the U.S. 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 and the federal and state governments in the U.S. have established incentive programs which have included royalty rate or production
tax 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 royalties paid by oil and gas producers to the applicable 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.

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.

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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. 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 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 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 theEnvironmental Protection and Enhancement Act(Alberta)
(the "EPEA") and theOil and Gas Conservation Act(Alberta), both of which impose certain
environmental responsibilities on oil and natural gas operators and working interest holders in Alberta and impose penalties for violations. In certain instances, the EPEA imposes significant
penalties for violations. In Saskatchewan, environmental compliance is governed by theEnvironmental Management and Protection Act(Saskatchewan) and
theOil and
Gas Conservation Act(Saskatchewan). Oil and gas activities in Manitoba are regulated by theOil and Gas Act(Manitoba). In
British Columbia, energy projects may be subject to review pursuant to the provisions of theEnvironmental 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. Other
environmental protection and management measures, including reclamation, are governed by theOil and Gas Activities Act(British Columbia) and the Environmental Management
Act(British Columbia). 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. Additionally,
in 2010 the Alberta provincial government and the Canadian federal government aligned in support of regulations that require the reporting of greenhouse gas emissions at facilities that meet or exceed
a 50,000 tonne per year carbon dioxide equivalent emissions threshold. Currently, Enerplus does not operate any facility classed within this category. 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

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not
yet been proven on a large scale. Subsequent to the International Climate Change meeting in Copenhagen in December 2009 and, regardless of the Cancun Conference of the Parties 2010 climate
talks, 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. Moreover, a recent
report from the National Roundtable on the Environment and Economy (2011) has recommended short-term actions for Canada to develop a national cap and trade program and to eventually link
with a North American cap and trade system if the U.S. eventually develops and implements its own cap and trade system. However, as the Canadian federal government continues to seek to align
its greenhouse gas regulations with those of the United States, it is unclear whether the Canadian federal government will pursue any short-term action 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 legislation, including theClean Air Act,Clean
Water Act, Resource Conservation and Recovery ActandEmergency Planning and Community Right-to-Know
Act.Regulations promulgated under these statutes 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.

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 adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing
provisions of the federalClean 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  Enerplus' operation of oil and natural gas wells could subject it to environmental costs, claims and
liabilities" and "Risk Factors  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

The following risk factors, together with other information contained in this Annual Information Form, should be carefully considered before investing in the
Common Shares. Each of these risks may negatively affect the trading price of the Common Shares or the amount of dividends that may, from time to time and at the discretion of the Corporation's board
of directors, be declared and paid by the Corporation to its shareholders.

Low or volatile oil and natural gas prices could have a material adverse effect on Enerplus' results of operations and financial condition.

Enerplus' results of operations and financial condition are dependent on the prices it receives for the oil and natural gas it produces and sells. Oil and
natural gas prices have fluctuated widely during recent years and may 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: (i) global energy supply, production and policies, including the ability of OPEC to set and maintain production levels in order to seek to influence prices for
oil; (ii) political conditions, including the risk of hostilities in the Middle East and global terrorism; (iii) global and domestic economic conditions including currency fluctuations;
(iv) the level of consumer demand; (v) the production and storage levels of North American natural gas and the supply and price of imported oil and liquefied natural gas;
(vi) weather conditions; (vii) the proximity of reserves and resources to, and capacity of, transportation facilities and the availability of refining capacity; (viii) the effect
of world-wide energy conservation and greenhouse gas reduction measures and the price and availability of alternative fuels; and (ix) 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.

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 Business" and "Business of
Enerplus", Enerplus is currently transitioning from an income model to a growth and income-oriented model. 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 resource plays, which 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 also transition to a more growth-oriented corporate model.

Dividends on the Corporation's Common Shares are variable.

Although the Corporation currently intends to pay monthly cash dividends to its shareholders, these cash dividends may be reduced or suspended. The amount of
cash available to the Corporation to pay dividends can vary significantly from period to period for a number of reasons, including among other things: (i) Enerplus' 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 Corporation 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) access to
equity markets; (vi) foreign currency exchange rates and interest rates; and (vii) the risk factors set forth in this Annual Information Form. The decision whether or not to pay
dividends and the amount of any such dividend is subject to the discretion of the board of directors of the Corporation, which regularly evaluates the Corporation's dividend policy and the

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solvency
test requirements of the ABCA. In addition, the level of dividends per Common Share will be affected by the number of outstanding Common Shares and other securities that may be entitled to
receive cash dividends or other payments. Dividends may be increased, reduced or suspended entirely depending on Enerplus' operations and the performance of its assets. The market value of the Common
Shares may deteriorate if the Corporation is unable to meet dividend expectations in the future, and that deterioration may be material.

To
the extent that Enerplus uses internally-generated cash flow to finance acquisitions, development costs and other significant capital expenditures, the amount of cash available to pay dividends to
the Corporation's shareholders may be reduced. To the extent that external sources of capital, including debt or the issuance of additional Common Shares or other securities of the Corporation, become
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 the
Corporation's cash dividend payments to its shareholders may be reduced or even eliminated.

The
board of directors of the Corporation has the discretion to determine the extent to which the Corporation's cash flow will be allocated to the payment of debt service charges as well as the
repayment of outstanding debt. The payments of interest and principal with respect to Enerplus' third party indebtedness, including the Credit Facilities, rank ahead of dividend payments that may be
made by the Corporation to its shareholders. An increase in the amount of funds used to pay debt service charges or reduce debt will reduce the amount of cash that may be available for the Corporation
to pay dividends to its shareholders. In addition, variations in interest rates and scheduled principal repayments, if and as required under the terms of the Credit Facilities, could result in
significant changes in the amount required to be applied to debt service. Certain covenants in agreements with lenders may also limit payments of dividends.

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 and natural gas reserves and resources, additional Common Shares
or other securities of the Corporation may be issued which may result in a decline in production per share and reserves and/or resources per share. Additionally, from time to time, the Corporation may
issue Common Shares 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 Common Shares 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 and natural gas 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 that may be available for the Corporation to pay dividends to its shareholders may
be reduced.

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

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. 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. Enerplus renewed the Bank Credit Facility in 2010, and accordingly it currently expires on June 30, 2013. 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. Any failure of a
member of the lending syndicate to fund its obligations under the Bank Credit Facility or to renew its commitment in respect of such Bank Credit Facility, or failure of Enerplus to obtain replacement
financing or financing on favourable terms, may have a material adverse effect on Enerplus' business, and dividends to shareholders may be materially reduced or eliminated, as repayment of such debt
has priority over dividend payments by the Corporation to its shareholders. Additionally, in 2010 Enerplus began to repay the first of five annual principal instalments of approximately
$53.7 million on $268.3 million of Senior Unsecured Notes issued in 2002, and $11 million per year must be repaid on $55.1 million of Senior Unsecured Notes issued in 2003
commencing October 1, 2011.

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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 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 Senior Unsecured Notes issued by Enerplus in
June 2002 and a foreign exchange swap that effectively fixes the principal payments on its Senior Unsecured Notes issued in October 2003, each as described in Notes 8
and 13 to Enerplus' audited consolidated financial statements for the year ended December 31, 2010.

Enerplus may be unable to add or develop additional reserves or resources.

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 through purchases or exploration. Exploitation, exploration and development risks arise for Enerplus and, as a result, may affect the value of the
Common Shares and dividends to shareholders 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.

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

The value of the Common Shares 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 judgments 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, such as, among other things; (i) historical production in the area compared with production rates from similar producing areas; (ii) future commodity prices, production and
development costs, royalties and capital expenditures; (iii) initial production rates and production decline rates; (iv) ultimate recovery of reserves and resources and the success of
future exploitation activities; (v) marketability of production; and (vi) the effects of government regulation and other government royalties or 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'

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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 are often based upon volumetric or probabilistic calculations and upon analogy to similar types of
reserves or resources, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of
the same reserves or resources based upon production history may result in variations or revisions in the estimated reserves or resources, and any such variations or revisions could
be material.

Reserve
and resource estimates may require revision based on actual production experience. Such figures have been determined based upon assumed oil, natural gas and NGLs prices and operating costs.
Market price fluctuations of commodity prices may render uneconomic the recovery of certain categories of petroleum or natural gas. Moreover, short term factors may impair the economic viability of
certain reserves or resources in any particular period.

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.

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

Furthermore,
potential investors should be aware that certain acquisitions, and in particular acquisitions of higher risk/higher growth assets, and the development of those acquired 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 adversely affect Enerplus' cash flow.

Enerplus
may also from time to time dispose of properties and assets, as evidenced by its disposition of significant non-core properties in 2010 as described under
"General Development of the Business". 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 Common Shares.

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An increase in operating costs or a decline in Enerplus' production level could have a material adverse effect on results of operations and financial condition.

Higher operating costs for Enerplus' properties will directly decrease the amount of Enerplus' cash flow. 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 operating costs or a significant decline in production could result in materially lower cash flow and,
therefore, could adversely affect the trading price of the Common Shares and reduce the amount that may be available for dividend payments by the Corporation to shareholders.

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. As of December 31, 2010, approximately 28% of Enerplus' production is from properties operated by third parties. This results in significant reliance on third party operators
in both the operation and development of such properties and control over
capital expenditures relating thereto. 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. 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.

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 Enerplus.

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, among other things: (i) capital or liquidity constraints experienced by such
parties, including restrictions imposed by lenders; (ii) accounting delays or adjustments for prior periods; (iii) delays in the sale or delivery of products or delays in the connection
of wells to a gathering system; (iv) weather related delays such as freeze-offs, flooding and premature thawing; (v) blowouts or other accidents; or (vi) 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 Enerplus' cash flow and the payment of cash dividends to its shareholders in a given period and expose Enerplus to additional third party
credit risks.

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

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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 adversely affect Enerplus'
financial position, including the amount of funds that may be available for dividend payments to shareholders.

In
addition, the Marcellus Shale Gas and the Bakken oil resource plays involve certain additional risks and uncertainties. The drilling and completion of wells and operations in the Bakken and in
shale gas plays, and in particular the Marcellus shale region, present certain challenges that differ from conventional oil and gas operations. Wells in these plays generally must be drilled deeper
than in many other areas, which makes the 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 Bakken and 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 wells. The management of water and the treatment of produced water from these wells
may be more costly than the management of produced water from other geologic formations.

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. Furthermore, from time to time, Enerplus may have disputes with industry partners as to
ownership rights of certain properties or resources.

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

Enerplus may acquire oil and natural gas properties and assets outside the geographic areas in which it has historically conducted its business and operations.
The expansion of Enerplus' activities into new resource plays and locations 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. Prior to 2009, Enerplus' operations and expertise
historically were 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. The acquisition of the Marcellus Properties in the northeast United States in September 2009 represented a new focus by Enerplus on shale gas outside its
traditional geographic areas. Although Enerplus will, in some cases, rely significantly upon its partners with respect to ongoing development, operations and certain future expansions in the Marcellus
shale gas region, Enerplus has relatively limited experience in the drilling and development of shale gas properties, and in particular the Marcellus shale gas region.

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.

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 have become more pronounced as a result of
increased drilling and development activities in these

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regions.
Additionally, 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, including as a result of maintenance activities, 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.

Additionally,
as Enerplus is subject to taxation as a Canadian corporation beginning in 2011 as a result of the Conversion from an income trust to a corporation, 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. or other foreign corporations that are able to minimize Canadian tax through the use of inter-company debt and cross-border tax planning measures or who have access to lower cost of
capital.

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 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 that may be available to pay as dividends to shareholders. Should Enerplus be unable to fully fund the cost of remedying an environmental claim, Enerplus might be
required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

Enerplus
utilizes horizontal drilling, multi-stage hydraulic fracturing, specially formulated drilling fluids and other technologies in connection with its drilling and completion activities. Recently
there has been some public concern over the hydraulic fracturing process with regards to shale gas formations in the United States and eastern Canada. Most of these concerns have raised
questions regarding the drilling fluids used in

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the
fracturing process, their effect on fresh water aquifers, the use of water in connection with completion operations and the ability of such water to be recycled. Certain government and regulatory
agencies in Canada and the United States have begun investigating the potential risks associated with the hydraulic fracturing process.

It
is anticipated that federal, provincial and state regulatory frameworks to address concerns related to hydraulic fracturing will continue to emerge. While Enerplus is unable to predict the impact
of any potential regulations upon its business, the implementation of new regulations with respect to water usage or hydraulic fracturing generally could increase Enerplus' costs of compliance,
operating costs, the risk of litigation and environmental liability, or negatively impact the Corporation's prospects, any of which may have a material adverse effect on Enerplus' business, financial
condition, results of operations.

Enerplus' expanded scope of activities and enlarged shareholder base may attract increased criticism and costly litigation.

The expansion of Enerplus' business activities, both geographically and with a new focus on exploration, may draw increased attention from special interest
groups opposed to development, which could have an adverse effect on market value. Higher visibility among investors may expose the Corporation to greater risk of class action lawsuits related to,
among other things, securities and environmental matters.

Changes in tax and other laws may adversely affect Enerplus and its shareholders.

Income tax laws, including tax laws that may affect the taxation of the Corporation or the Corporation's dividends to its shareholders, 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 Corporation and its shareholders. 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, the imposition of specific drilling obligations, control over
the development and abandonment of fields (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. Additionally, Enerplus' entry into new jurisdictions and its adoption of new technology may
attract additional regulatory oversight which could result in higher costs or require changes to proposed operations. For example, U.S. federal and state governments have increased their
scrutiny of the usage and disposal of chemicals and water used in fracturing procedures in the Marcellus shale, while cities such as Philadelphia and New York have called for bans on drilling
in their local watersheds. The State of Maryland is currently reviewing its oil and gas drilling and development permitting process, which could potentially include limiting or prohibiting certain
types of oil and gas activities in the state. More activity by Enerplus on Indian land in North Dakota also may increase compliance obligations under local or tribal rules. 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
negatively impact the development of oil and gas properties and assets, reduce demand for crude oil and natural gas or impose increased costs on oil and gas companies, any of which could have a
material adverse impact on Enerplus.

Additionally,
various levels of Canadian and United States governments are considering legislation to reduce emissions of greenhouse gases. See "Industry
Conditions  Environmental Regulation" for a description 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

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costs;
however, they could be significant. Any of the foregoing could have adverse effects on Enerplus' business, financial position, results of operations and prospects.

In
Alberta, the conversion of Enerplus' business from an income trust to a corporation effective January 1, 2011 pursuant to the Conversion included the amalgamation of different Energy
Resources Conservation Board ("ERCB") licensees into one. As part of the ERCB compliance strategy, the Corporation's compliance performance will be
monitored for an unacceptable risk rate, ratio, percentage, or number of non-compliance's in either the same or different compliance categories that, prior to the amalgamation, were
distributed amongst many license holders. If more than two ERCB high risks are received in the same category, Enerplus could be put on "Monitoring" or "Persistent" non-compliance status,
which could lead to enforcement consequences.

The Corporation's adoption of IFRS may adversely impact the Corporation's reported financial results.

The requirement for the Corporation to implement IFRS to replace Canadian GAAP effective January 1, 2011 may materially affect the Corporation's
financial results as reported in its financial statements and its results of operations. For a detailed description of the impact of the adoption of IFRS on Enerplus' financial statements, see
"Recent Canadian Accounting and Related Pronouncements  Convergence of Canadian GAAP with International Financial Reporting Standards
("IFRS")" in Enerplus' MD&A for the year ended December 31, 2010. In addition, following the adoption of IFRS, Enerplus will no longer be required to reconcile
its financial statements to U.S. GAAP under certain U.S. SEC requirements. IFRS may differ from U.S. GAAP in some significant respects, and therefore Enerplus' financial
information presented in accordance with IFRS may not be directly comparable with financial information presented by U.S. companies in accordance with U.S. GAAP.

Lower oil and gas prices and higher costs increase the risk of write-downs of Enerplus' oil and gas property assets and goodwill.

Under IFRS, when indicators of impairment exist, the carrying value of the Exploration and Evaluation ("E&E")
assets as well as each Cash Generating Unit ("CGU"), including goodwill attributed to the CGU, is compared to its recoverable amount. The recoverable
amount is defined as the higher of the fair value less cost to sell or value in use. A decline in oil and gas prices is an indicator of CGU impairment and may result in the estimated recoverable
amount of Enerplus' developed oil and natural gas properties being less than their carrying value on the balance sheet, resulting in a write-down of the CGU assets. All CGU write-downs are
first recorded against the goodwill in the CGU, with the remainder reducing the book value of the developed oil and gas assets in the CGU. E&E assets are tested for impairment prior to being
transferred to a CGU. Where the recoverable amount is less than the book value of E&E assets, the asset is reduced to the recoverable amount.

The
offset for any goodwill, E&E or CGU impairment is recorded as a charge to net income. While these write-downs would not affect cash flow from operations, the charge to earnings may be viewed
unfavourably in the market. Impairments to goodwill and E&E assets are not reversed, however should the conditions that caused the CGU asset impairment reverse in the future Enerplus would be required
to reverse all, or a portion of the impairment previously recorded.

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

Shareholders are entirely dependent on the management of Enerplus with respect to the acquisition of oil and natural gas properties and assets, the exploration
for and development of additional reserves and resources and the management and administration of all matters relating to Enerplus and its properties and assets. The loss of the services of key
individuals could have a detrimental effect on the Corporation. Further, Enerplus' recent acquisitions and activities in various resource plays will require different skill sets than those needed in
developing its traditional asset base. There is no assurance that the Corporation will be able to attract and retain personnel with the technical expertise necessary to develop such properties, which
could adversely effect the Corporation's exploration and development plans.

Conflicts of interest may arise between the Corporation and its directors and officers.

Circumstances may arise where directors and officers of the Corporation 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.

Changes in market-based factors may adversely affect the trading price of the Common Shares.

The market price of the Common Shares is primarily a function of the value of the properties owned by Enerplus and anticipated dividends paid to its
shareholders. The market price of the Common Shares is therefore sensitive to a variety of market-based factors including, but not limited

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to,
interest rates and the comparability of the Common Shares to other yield-oriented securities. Any changes in these market-based factors may adversely affect the trading price of the
Common Shares.

United States and other non-resident shareholders 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 dividends or other
property paid by the Corporation to shareholders who are not residents of Canada, and these taxes may change from time to time. In addition, the country in which the shareholder is resident may impose
local taxes on such dividends and these taxes may change from time to time. For example, in the United States, the "qualified dividend" rate of 15% tax applied to the Corporation's dividends
under current
U.S. federal income tax laws was scheduled to expire at the end of 2010 but was extended through 2012, but there is no assurance that this reduced tax rate will be extended beyond such date in
its present form by the U.S. government.

Non-resident shareholders are subject to foreign exchange risk on the dividends that they may receive from the Corporation.

Any dividends that may be declared by the Corporation from time to time 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 dividend will be reduced when converted to their home currency.

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

The Corporation is formed under the laws of Alberta, Canada, and its principal place of business is in Canada. Most of the directors and officers of the
Corporation are residents of Canada and some of the experts who provide services to the Corporation (such as its auditors and some of its independent reserve engineers) are residents of Canada, and
all or a substantial portion of their assets and the Corporation's 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 the Corporation or any of its directors, officers or representatives of experts who are not residents of the United States,
in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws
of any state within the United States.

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Market for Securities

The Common Shares are listed and posted for trading on the TSX and the NYSE under the trading symbol "ERF". Prior to completion of the Conversion on
January 1, 2011, the Fund's Trust Units were listed and posted for trading on the TSX under the symbol "ERF.UN" and on the NYSE under the symbol "ERF".

The
following table sets forth certain trading information for the Trust Units on the TSX and the United States composite trading information for 2010.

|          |  | TSX    |  | U.S. Composite Trading
|--------- |  | ------ |  | ----------------------
|Month     |  | High   |  | Low                   
|          |  |       
|January   |  | $24.96 |  | $22.46                
|February  |  | 23.88  |  | 22.45                 
|March     |  | 24.20  |  | 23.30                 
|April     |  | 25.00  |  | 23.50                 
|May       |  | 25.07  |  | 18.22                 
|June      |  | 24.23  |  | 22.30                 
|July      |  | 23.97  |  | 22.53                 
|August    |  | 24.45  |  | 23.07                 
|September |  | 26.57  |  | 24.14                 
|October   |  | 28.20  |  | 26.28                 
|November  |  | 29.67  |  | 26.76                 
|December  |  | $31.84 |  | $28.37                
|          |  |       

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Directors and Officers

DIRECTORS OF THE CORPORATION

The directors of the Corporation are elected by the shareholders of the Corporation at each annual meeting of shareholders. All directors serve until the next
annual meeting or until a successor is elected or appointed or until the director is removed at a meeting of shareholders. The name, municipality of residence, year of appointment as a director of the
Corporation (or its predecessor EnerMark Inc., the administrator of the Fund prior to the Conversion) and principal occupation for the past five years for each director of the
Corporation are set forth below.

|Name and Residence                                       |  | Director Since |  | Principal Occupation for Past Five Years                                                                                                                                                                                                                                                                                                                                             | 
|-------------------------------------------------------- |  | -------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | 
|                                                        
|Edwin V. Dodge(4)(6)
Vancouver, British Columbia, Canada |  | May 2004       |  | Corporate director.                                                                                                                                                                                                                                                                                                                                                                  | 
|Robert B. Hodgins(2)(3)
Calgary, Alberta, Canada         |  | November 2007  |  | Independent businessman.                                                                                                                                                                                                                                                                                                                                                             | 
|Gordon J. Kerr
Calgary, Alberta, Canada                  |  | May 2001       |  | President and Chief Executive Officer of Enerplus.                                                                                                                                                                                                                                                                                                                                   | 
|Douglas R. Martin(1)
Calgary, Alberta, Canada            |  | September 2000 |  | President of Charles Avenue Capital Corp. (a private merchant banking company).                                                                                                                                                                                                                                                                                                      | 
|David P. O'Brien(3)(7)
Calgary, Alberta, Canada          |  | March 2008     |  | Corporate director, including Chairman of EnCana Corporation (a TSX and NYSE-listed oil and gas company) and Chairman of the Royal Bank of Canada (a TSX and NYSE-listed Canadian chartered bank).                                                                                                                                                                                   | 
|Elliott Pew(5)
Boerne, Texas, U.S.A.                     |  | September 2010 |  | Director of Common Resources II, L.L.C. (a private oil and gas company) since May 2010. Prior thereto, Chief Operating Officer of Common Resources L.L.C. (a private oil and gas company) from March 2007 to May 2010. Prior
thereto, Executive Vice President Exploration of Newfield Exploration Company (an NYSE-listed oil and gas company) from November 2004 to December 2006. | 
|Glen D. Roane(2)(3)
Canmore, Alberta, Canada             |  | June 2004      |  | Corporate director.                                                                                                                                                                                                                                                                                                                                                                  | 
|W.C. (Mike) Seth(3)(5)
Calgary, Alberta, Canada          |  | August 2005    |  | President of Seth Consultants Ltd. (a private consulting firm) since June 2006. From July 2005 to June 2006, Mr. Seth was Chairman of McDaniel & Associates Consultants Ltd. ("McDaniel") (a petroleum engineering consulting firm). Prior thereto, President and Managing Director of McDaniel.                                                                                     | 
|Donald T. West(5)(6)
Calgary, Alberta, Canada            |  | April 2003     |  | Independent businessman.                                                                                                                                                                                                                                                                                                                                                             | 
|Harry B. Wheeler(2)(4)
Calgary, Alberta, Canada          |  | January 2001   |  | President of Colchester Investments Ltd. (a private investment firm).                                                                                                                                                                                                                                                                                                                | 
|Clayton H. Woitas(5)(6)
Calgary, Alberta, Canada         |  | March 2008     |  | President of Range Royalty Management Ltd. (a private energy company) since June 2006. Prior thereto, Chairman and Chief Executive Officer of Profico Energy Management Ltd. (a private oil and gas company).                                                                                                                                                                        | 
|Robert L. Zorich(4)
Houston, Texas, USA                  |  | January 2001   |  | Managing Director of EnCap Investments L.P. (a private firm that provides private equity financing to the oil and gas industry).                                                                                                                                                                                                                                                     | 
|                                                        

Notes:

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OFFICERS OF THE CORPORATION

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

|Name and Residence                               |  | Office                                                   |  | Principal Occupation for Past Five Years                                                                                                                                                                                                                                                                                                                                                     | 
|------------------------------------------------ |  | -------------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | 
|                                                
|Gordon J. Kerr
Calgary, Alberta, Canada          |  | President & Chief Executive Officer                      |  | President & Chief Executive Officer of Enerplus.                                                                                                                                                                                                                                                                                                                                             | 
|Ian C. Dundas
Calgary, Alberta, Canada           |  | Executive Vice President                                 |  | Executive Vice President, Enerplus since March 2010. Prior thereto, Senior Vice President, Business Development of Enerplus.                                                                                                                                                                                                                                                                 | 
|Robert J. Waters
Calgary, Alberta, Canada        |  | Senior Vice President & Chief Financial Officer          |  | Senior Vice President & Chief Financial Officer of Enerplus.                                                                                                                                                                                                                                                                                                                                 | 
|Jo-Anne M. Caza
Calgary, Alberta, Canada         |  | Vice President, Corporate & Investor Relations           |  | Vice President, Corporate & Investor Relations since January 2008. Prior thereto, Vice President, Investor Relations of Enerplus.                                                                                                                                                                                                                                                            | 
|Raymond J. Daniels
Calgary, Alberta, Canada      |  | Vice President, Development Services                     |  | Vice President, Development Services of Enerplus since July 2009. Prior 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
Calgary, Alberta, Canada          |  | Vice President, Finance                                  |  | Vice President, Finance of Enerplus.                                                                                                                                                                                                                                                                                                                                                         | 
|Dana W. Johnson
Denver, Colorado, U.S.A.         |  | President, U.S. Operations                               |  | President, U.S. Operations of Enerplus since May 2008. Prior thereto, Senior Vice 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).                                                                                                      | 
|Robert A. Kehrig
Calgary, Alberta, Canada        |  | Vice President, Resource Development                     |  | Vice President, Resource Development of Enerplus since October 2008. Prior thereto, Manager in Enerplus' Business Development group.                                                                                                                                                                                                                                                         | 
|Jennifer F. Koury
Calgary, Alberta, Canada       |  | Vice President, Corporate Services                       |  | Vice President, Corporate Services of Enerplus since October 2006. Prior thereto, a private consultant.                                                                                                                                                                                                                                                                                      | 
|Eric G. Le Dain
Calgary, Alberta, Canada         |  | Vice President, Strategic Planning, Reserves & Marketing |  | Vice President, Strategic Planning, Reserves & Marketing of Enerplus since March 2010. Prior thereto, Vice President, Regulatory, Environment and Marketing of Enerplus since 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
Calgary, Alberta, Canada          |  | Vice President, General Counsel & Corporate Secretary    |  | Vice President, General Counsel & Corporate Secretary of Enerplus.                                                                                                                                                                                                                                                                                                                           | 
|Robert W. Symonds
Calgary, Alberta, Canada       |  | Vice President, Canadian Operations                      |  | Vice President, Canadian Operations of Enerplus since March 2009. Prior thereto, Vice 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
Calgary, Alberta, Canada        |  | Vice President, Land                                     |  | Vice President, Land of Enerplus since November 2008. Prior thereto, Vice President, 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
Calgary, Alberta, Canada |  | Controller, Finance                                      |  | Controller, Finance of Enerplus.                                                                                                                                                                                                                                                                                                                                                             | 
|                                                

COMMON SHARE OWNERSHIP

As of March 2, 2011, the directors and officers of the Corporation named above beneficially own, or control or exercise direction over, directly
or indirectly, an aggregate of 2,438,011 Common Shares, representing approximately 1.4% of the outstanding Common Shares as of that date.

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CONFLICTS OF INTEREST

Certain of the directors and officers named above may be directors or officers of issuers which are in competition with the Corporation, and as such may
encounter conflicts of interests in the administration of their duties with respect to the Corporation. In situations where conflicts
of interest arise, the Corporation expects the applicable director or officer to declare the conflict and, if a director of the Corporation, abstain from voting in respect of such matters on behalf of
the Corporation.

See
"Risk Factors  Conflicts of interest may arise between the Corporation and its directors
and officers".

AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE

The disclosure regarding the Corporation's Audit & Risk Management Committee required under National Instrument 52-110 adopted
by certain of the Canadian securities regulatory authorities is contained in Appendix D 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 2010 a party to, and none of Enerplus' property is or was during 2010 the subject of, any legal proceeding that involves a claim for damages (exclusive of interest and costs) greater than 10%
of its current assets as at December 31, 2010, and Enerplus has no knowledge of any such proceeding being contemplated.

Interest of Management and Others in Material Transactions

To the knowledge of the directors and executive officers of the Corporation, none of the directors or executive officers of the Corporation 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 Corporation'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, 2008 or in any proposed transaction that has
materially affected or is reasonably expected to materially affect Enerplus.

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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.

Copies
of the following documents entered into the normal course of business and relating to the Credit Facilities have been filed on the Fund's SEDAR profile at
www.sedar.com and on Form 6-K on the Fund's EDGAR profile at www.sec.gov, as they were filed prior to the
January 1, 2011 Conversion:

Copies
of the following documents affecting the rights of securityholders have been filed on the Corporation's SEDAR profile at www.sedar.com and on
Form 6-K on the Corporation's EDGAR profile at www.sec.gov, as they were filed after the January 1, 2011 Conversion:

Interests of Experts

McDaniel
prepared the McDaniel Reports in respect of the reserves attributable to Enerplus' oil and natural gas properties in Canada and the western United States, a summary of which is
contained in this Annual Information Form. McDaniel also audited the estimate of contingent resources attributable to Enerplus' interests in the Fort Berthold, North Dakota area, which is referred to
in this Annual Information Form. As of the dates of the McDaniel Reports, the "designated professionals" (as defined in
Form 51-102F2 Annual Information Formof the Canadian securities regulatory authorities) of
McDaniel, as a group, beneficially owned, directly or indirectly, less than 1% of the Corporation's outstanding Common Shares. 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 Corporation's outstanding Common Shares.

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.

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Transfer Agent and Registrar

The transfer agent and registrar for the Common Shares 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 Common Shares in the United States.

Additional Information

Additional information relating to the Corporation may be found on the Corporation's profile on the SEDAR website at www.sedar.com,
on the EDGAR website at www.sec.gov and on the Corporation's website at www.enerplus.com. Additional information, including directors' and
officers' remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance under equity compensation plans, as applicable, is contained in the
Corporation's information circular and proxy statement dated March 11, 2011 for its 2011 annual general meeting of shareholders. Furthermore, additional financial information relating to
the Corporation is provided in Enerplus' audited consolidated financial statements and MD&A for the year ended December 31, 2010. Shareholders who wish to receive printed copies of these
documents free of charge should contact the Corporation's Corporate & Investor Relations Department using the contact information on the final page of this Annual Information Form.

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APPENDIX A

Appendix A  Reports on Reserves Data by Independent Qualified Reserves Evaluator or Auditor

January 28, 2011

Enerplus Corporation3000, 333 - 7th Avenue SW
Calgary, Alberta
T2P 2Z1

Attention:
The Board of Directors of Enerplus Corporation

To the Board of Directors of Enerplus Corporation (the "Company"):



|Preparation Date of |  | Location of |  | Net Present Value of Future Net Revenue
(before income taxes, 10% discount rate)
|------------------- |  | ----------- |  | --------------------------------------------------------------------------------
|Evaluation Report   |  | Reserves    |  | Audited                                                                         
|                   
|                    |  |             |  | (in $ thousands)                                                                
|January 28, 2011    |  | Canada      |  |                                                                                
|                   

Executed
as to our report referred to above:

|MCDANIEL & ASSOCIATES CONSULTANTS LTD."P.A. Welch"P.A. Welch, P. Eng.
President & Managing Director
Calgary, Alberta
January 28, 2011 |  | 
|------------------------------------------------------------------------------------------------------------------------------------- |  | 

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January 28, 2011

Enerplus Resources (USA) Corporation1300 Wells Fargo Center
Denver, Colorado, USA
80203

Attention:
The Board of Directors of Enerplus Corporation

To the Board of Directors of Enerplus Corporation (the "Company"):



|Preparation Date of |  | Location of   |  | Net Present Value of Future Net Revenue
(before income taxes, 10% discount rate)
|------------------- |  | ------------- |  | --------------------------------------------------------------------------------
|Evaluation Report   |  | Reserves      |  | Audited                                                                         
|                   
|                    |  |               |  | (in US$ thousands)                                                              
|January 28, 2011    |  | United States |  |                                                                                
|                   

Executed
as to our report referred to above:

|MCDANIEL & ASSOCIATES CONSULTANTS LTD."P.A. Welch"P.A. Welch, P. Eng.
President & Managing Director
Calgary, Alberta
January 28, 2011 |  | 
|------------------------------------------------------------------------------------------------------------------------------------- |  | 

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APPENDIX B

Appendix B  Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor

To
the board of directors of Enerplus Corporation (the "Company"):



Independent Qualified

Description and Preparation

Location of Reserves
(Country or Foreign

Net Present Value of Future Net Revenue
(before U.S. federal income taxes,
10% discount rate)Reserves Evaluator

Date of Evaluation Report

Geographic Area)


Audited


Evaluated


Reviewed


Total(US$ thousands)Haas Petroleum Engineering Services, Inc.

Estimate of Reserves and Future Net Revenue to the Enerplus Corporation Interest as of December 31, 2010, dated February 10, 2011

Pennsylvania and West Virginia, USA

$


$
208,258

$


$
208,258


Executed
as to our report referred to above:

|HAAS PETROLEUM ENGINEERING SERVICES, INC.Dallas, Texas, U.S.A.
February 23, 2011
"Robert W. Haas"Robert W. Haas, P.E.
President |  | 
|------------------------------------------------------------------------------------------------------------------------------- |  | 

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APPENDIX C

Appendix C  Report of Management and Directors on Oil and Gas Disclosure

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 Enerplus Corporation (the "Company") are responsible for the preparation and disclosure of information with respect to the Company'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, 2010, estimated using forecast prices and costs.

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

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

The
Reserves Committee of the board of directors of the Company has reviewed the Company'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 the Company has, on the recommendation of the Reserves Committee, approved:

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

|ENERPLUS CORPORATION                               |  |                                       
|-------------------------------------------------- |  | --------------------------------------
|"Gordon J. Kerr"                                   |  | "Ian C. Dundas"                       
|                                                   |  |                                       
|Gordon J. Kerr
President & Chief Executive Officer |  | Ian C. Dundas
Executive Vice President
|"W.C. (Mike) Seth"                                 |  | "Donald T. West"                      
|                                                   |  |                                       
|W.C. (Mike) Seth
Director                          |  | Donald T. West
Director               

March 11, 2011

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APPENDIX D

Appendix D  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 the Corporation is attached as
Schedule 1 to this Appendix D.

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 (Honors B.A. (Business), C.A.)
(Director since November 2007)Other Public Directorships AltaGas Ltd. (energy midstream services) Fairborne Energy Ltd. (oil and gas
exploration and production company) MGM Energy Corp. (oil and gas exploration and production company) Orion
Oil & Gas Corporation (oil and gas exploration and production company) Skope Energy Inc. (oil and gas exploration and production company) MEG Energy Corp. (oil sands company) |  | Mr. Hodgins has been an independent businessman since November 2004. Prior 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,
Mr. Hodgins held the position of Vice President and Treasurer of Canadian Pacific Limited (a diversified energy, transportation and hotels company) from 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited
(a TSX and NYSE-listed energy transportation company) from 1993 to 1998. Mr. Hodgins received an Honors Bachelor of Arts in Business from the Richard Ivey School of Business at the University of Western Ontario in 1975 and received a
Chartered Accountant designation and was admitted as a member of the Institute of Chartered Accountants of Ontario in 1977 and Alberta in 1991.  | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Mr. Glen D. Roane (B.A., MBA)
(Director since June 2004)Other Public Directorships Badger Daylighting Ltd. (provider of non-destructive excavation services) Logan
International Inc. (oil and gas service business) SilverBirch Energy Corporation (oil sands company)                                                                                                                                                                                                             |  | 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) UTS Energy Corporation, 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's University in Kingston, Ontario. | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

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|Name (Director Since)                                                                               |  | Principal Occupation and Biography                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 | 
|--------------------------------------------------------------------------------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | 
|                                                                                                   
|Mr. Harry B. Wheeler (B.Sc. (Geology))
(Director since January 2001)Other Public Directorships Nil |  | Mr. Wheeler has been the President of Colchester Investments Ltd., a private investment firm, since 2000. From 1962 to 1966, Mr. Wheeler worked with Mobil Oil in Canada and Libya and from 1967 to 1972 was
employed by International Resources Ltd., in London, England and Denver, Colorado. He was a Director of Quintette Coal Ltd., Vice President of Amalgamated Bonanza Petroleum Ltd. and operator of his private company before founding Cabre
Exploration Ltd. ("Cabre"), a public oil and gas company, in 1980. Mr. Wheeler was Chairman of Cabre until it was acquired by EnerMark Income Fund (a predecessor of Enerplus) in December 2000. Mr. Wheeler is currently a
director of Magellan Resources Ltd. and Knowledge Energy Inc., private oil and gas companies. 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 Corporation's auditors and the fees paid to the Corporation's
auditors. Prior to the engagement of the Corporation'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 2010 and 2009 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 Corporation.

E. EXTERNAL AUDITOR SERVICE FEES

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

|                      |  |   | 2010             |  |  |   | 2009    | 
|--------------------- |  | - | ---------------- |  |  | - | ------- | 
|                      |  |  
|                      |  |   | (in $ thousands) | 
|Audit fees(1)         |  | $ | 809.3            |  |  | $ | 790.2   | 
|Audit-related fees(2) |  |   |                 |  |  |   |        | 
|Tax fees(3)           |  |   | 212.1            |  |  |   | 367.3   | 
|All other fees(4)     |  |   | 57.0             |  |  |   |        | 
|                      |  |  
|                      |  | $ | 1,078.4          |  |  | $ | 1,157.3 | 
|                      |  |  

Notes:

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Audit & Risk Management Committee Charter

I. AUTHORITY

The Audit & Risk Management Committee (the "Committee") of the Board of Directors (the "Board") of Enerplus Corporation
(the "Corporation") 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 shareholders of the Corporation 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 & 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 Corporation 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:

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 Corporation'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 Corporation.

III. COMPOSITION AND COMPETENCY OF THE COMMITTEE

Each member of the Committee shall be unrelated to the Corporation and, as such, shall be free from any relationship that may interfere with the exercise of his
or her independent judgment 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.

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

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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

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

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

Review of Business Risks

Other Matters

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

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APPENDIX E

Appendix E  Supplemental Information About Oil and Gas Producing Activities

The following disclosures including proved reserves, future net cash flows, and costs incurred attributable to Enerplus' conventional crude oil and natural gas
operations 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 Corporation 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 Corporation'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, 2010, 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.

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Enerplus'
December 31, 2010 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, Pennsylvania, West Virginia, Wyoming and Utah. Enerplus' net proved reserves summarized in the
following chart represent the Corporation's lessor royalty, overriding royalty, and working interest share of reserves, after deduction of any Crown, freehold and overriding royalties:

|                                                               |                   | Canada       |        | United States |         | Total  
|-------------------------------------------------------------- | ----------------- | ------------ | ------ | ------------- | ------- | -------
|                                                               |                   | Oil and
NGLs |        | Natural
Gas   |         | Bitumen
|                                                               |                   |              |        |              
|                                                               |                   | (Mbbls)      |        | (MMcf)        |         | (Mbbls)
|Proved Developed and Undeveloped Reserves at December 31, 2007 |                   | 96,145       |        | 674,457       |         | 8,424  
|                                                               |                   |              |        |              
|Purchases of reserves in place                                 |                   | 5,241        |        | 296,849       |         |       
|Sales of reserves in place                                     |                   |             |        |              |         | (8,424 
|Discoveries and extensions                                     |                   | 2,034        |        | 18,225        |         |       
|Revisions of previous estimates                                |                   | (7,802       | )      | (57,449       | )       |       
|Improved recovery                                              |                   | 1,939        |        | 2,699         |         |       
|Production                                                     |                   | (8,958       | )      | (96,664       | )       |       
|                                                               |                   |              |        |              
|Proved Developed and Undeveloped Reserves at December 31, 2008 |                   | 88,599       |        | 838,117       |         |       
|                                                               |                   |              |        |              
|Purchases of reserves in place                                 |                   | 398          |        |              |         |       
|Sales of reserves in place                                     |                   | (1,019       | )      | (618          | )       |       
|Discoveries and extensions                                     |                   | 1,618        |        | 2,987         |         |       
|Revisions of previous estimates                                |                   | 7,423        |        | (265,677      | )       |       
|Improved recovery                                              |                   | 85           |        | 184           |         |       
|Production                                                     |                   | (8,580       | )      | (100,581      | )       |       
|                                                               |                   |              |        |              
|Proved Developed and Undeveloped Reserves at December 31, 2009 |                   | 88,524       |        | 474,412       |         |       
|                                                               |                   |              |        |              
|Purchases of reserves in place                                 |                   | 224          |        | 1,965         |         |       
|Sales of reserves in place                                     |                   | (13,725      | )      | (32,508       | )       |       
|Discoveries and extensions                                     |                   | 3,138        |        | 4,966         |         |       
|Revisions of previous estimates                                |                   | 3,151        |        | 20,361        |         |       
|Improved recovery                                              |                   | 85           |        | 6,074         |         |       
|Production                                                     |                   | (7,328       | )      | (85,917       | )       |       
|                                                               |                   |              |        |              
|Proved Developed and Undeveloped Reserves at December 31, 2010 |                   | 74,069       |        | 389,353       |         |       
|                                                               |                   |              |        |              
|Proved Developed Reserves                                      |                   |              |        |               |         |        
|                                                               | December 31, 2007 |              | 90,715 |               | 533,654 |        
|                                                               | December 31, 2008 |              | 79,485 |               | 683,044 |        
|                                                               | December 31, 2009 |              | 82,384 |               | 468,746 |        
|December 31, 2010                                              |                   | 68,906       |        | 372,550       |         |       
|                                                               |                   |              |        |              

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B. CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

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

|                                                          |  |   | 2010             |   |   | 2009       |   |   | 2008       |   | 
|--------------------------------------------------------- |  | - | ---------------- | - | - | ---------- | - | - | ---------- | - | 
|                                                         
|                                                          |  |   | (in $ thousands) |   |  
|Capitalized costs(1)                                      |  | $ | 8,261,974        |   | $ | 7,673,238  |   | $ | 7,322,721  |   | 
|Less accumulated depletion, depreciation and amortization |  |   | (5,230,587       | ) |   | (4,879,015 | ) |   | (4,005,780 | ) | 
|                                                         
|Net capitalized costs                                     |  | $ | 3,031,387        |   | $ | 2,794,223  |   | $ | 3,316,941  |   | 
|                                                         

Note:

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. The entire carry commitment
relating to Enerplus' 2009 Marcellus acquisition was included in 2009 property acquisition costs, and as a result 2010 property acquisition cost exclude such carry commitment amounts satisfied
during the year. 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, 2010
|-------------------------- | -------- | ------------------------------------
|                           |          |                                     
|                          
|                           |          |                                     
|Acquisition of properties: |          |                                     
|                           | Proved   |                                     
|                           | Unproved |                                     
|Exploration costs          |          |                                     
|Development costs          |          |                                     
|Asset retirement costs     |          |                                     
|                          
|                           |          | $                                   
|                          

|
|

|                           |          | For the Year Ended December 31, 2009
|-------------------------- | -------- | ------------------------------------
|                           |          |                                     
|                          
|                           |          |                                     
|Acquisition of properties: |          |                                     
|                           | Proved   |                                     
|                           | Unproved |                                     
|Exploration costs          |          |                                     
|Development costs          |          |                                     
|Asset retirement costs     |          |                                     
|                          
|                           |          | $                                   
|                          

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|
|

|                           |          | For the Year Ended December 31, 2008
|-------------------------- | -------- | ------------------------------------
|                           |          |                                     
|                          
|                           |          |                                     
|Acquisition of properties: |          |                                     
|                           | Proved   |                                     
|                           | Unproved |                                     
|Exploration costs          |          |                                     
|Development costs          |          |                                     
|Asset retirement costs     |          |                                     
|                          
|                           |          | $                                   
|                          

D. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to Enerplus' oil and gas producing activities for the years ended
December 31, 2010, 2009 and 2008:

|                                                           |                                                      | For the Year Ended December 31, 2010
|---------------------------------------------------------- | ---------------------------------------------------- | ------------------------------------
|                                                           |                                                      |                                     
|                                                          
|                                                           |                                                      |                                     
|Revenue                                                    |                                                      |                                     
|                                                           | Sales(1)                                             |                                     
|Deduct(2)                                                  |                                                      |                                     
|                                                           | Production Costs(3)                                  |                                     
|                                                           | Depletion, depreciation, amortization and accretion  |                                     
|                                                           | Current and Deferred income tax provision (recovery) |                                     
|                                                          
|Results of operations for oil and gas producing activities |                                                      | $                                   
|                                                          

|
|

|                                                           |                                                                 | For the Year Ended December 31, 2009
|---------------------------------------------------------- | --------------------------------------------------------------- | ------------------------------------
|                                                           |                                                                 |                                     
|                                                          
|                                                           |                                                                 |                                     
|Revenue                                                    |                                                                 |                                     
|                                                           | Sales(1)                                                        |                                     
|Deduct(2)                                                  |                                                                 |                                     
|                                                           | Production Costs(3)                                             |                                     
|                                                           | Depletion, depreciation, amortization, accretion and impairment |                                     
|                                                           | Current and Deferred income tax provision (recovery)            |                                     
|                                                          
|Results of operations for oil and gas producing activities |                                                                 | $                                   
|                                                          

|
|

|                                                           |                                                                 | For the Year Ended December 31, 2008
|---------------------------------------------------------- | --------------------------------------------------------------- | ------------------------------------
|                                                           |                                                                 |                                     
|                                                          
|                                                           |                                                                 |                                     
|Revenue                                                    |                                                                 |                                     
|                                                           | Sales(1)                                                        |                                     
|Deduct(2)                                                  |                                                                 |                                     
|                                                           | Production Costs(3)                                             |                                     
|                                                           | Depletion, depreciation, amortization, accretion and impairment |                                     
|                                                           | Current and Deferred income tax provision (recovery)            |                                     
|                                                          
|Results of operations for oil and gas producing activities |                                                                 | $                                   
|                                                          

Notes:

E-4      ENERPLUS2010 ANNUAL INFORMATION
FORM

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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 and natural gas liquids reserve and production volumes estimated by Enerplus' independent
engineering consultants. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating Enerplus 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 Enerplus' reserves.

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

|                                                         |  | As at December 31, 2010
|-------------------------------------------------------- |  | -----------------------
|                                                         |  |                        
|                                                        
|                                                         |  |                        
|Future cash inflows                                      |  | $                      
|Future production costs                                  |  |                        
|Future development and asset retirement costs            |  |                        
|Future income tax expenses                               |  |                        
|                                                        
|Future net cash flows                                    |  | $                      
|Deduction: 10% annual discount factor                    |  |                        
|                                                        
|Standardized measure of discounted future net cash flows |  | $                      
|                                                        

|
|

|                                                         |  | As at December 31, 2009
|-------------------------------------------------------- |  | -----------------------
|                                                         |  |                        
|                                                        
|                                                         |  |                        
|Future cash inflows                                      |  | $                      
|Future production costs                                  |  |                        
|Future development and asset retirement costs            |  |                        
|Future income tax expenses                               |  |                        
|                                                        
|Future net cash flows                                    |  | $                      
|Deduction: 10% annual discount factor                    |  |                        
|                                                        
|Standardized measure of discounted future net cash flows |  | $                      
|                                                        

|
|

|                                                         |  | As at December 31, 2008
|-------------------------------------------------------- |  | -----------------------
|                                                         |  |                        
|                                                        
|                                                         |  |                        
|Future cash inflows                                      |  | $                      
|Future production costs                                  |  |                        
|Future development and asset retirement costs            |  |                        
|Future income tax expenses                               |  |                        
|                                                        
|Future net cash flows                                    |  | $                      
|Deduction: 10% annual discount factor                    |  |                        
|                                                        
|Standardized measure of discounted future net cash flows |  | $                      
|                                                        

ENERPLUS2010 ANNUAL INFORMATION
FORME-5

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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:

|                  |                                                                              |   | 2010            |      |   | 2009  |        |   | 2008  |        |  
|----------------- | ---------------------------------------------------------------------------- | - | --------------- | ---- | - | ----- | ------ | - | ----- | ------ | -
|                 
|                  |                                                                              |   | (in $ millions) |      |  
|Beginning of year |                                                                              | $ | 2,081           |      | $ | 2,719 |        | $ | 3,990 |        |  
|                  | Sales of oil and natural gas produced, net of production costs               |   |                 | (785 | ) |       | (1,233 | ) |       | (1,608 | )
|                  | Net changes in sales prices and production costs                             |   |                 | 918  |   |       | 328    |   |       | (1,276 | )
|                  | Changes in previously estimated development costs incurred during the period |   |                 | 540  |   |       | 285    |   |       | 235    |  
|                  | Changes in estimated future development costs                                |   |                 | (689 | ) |       | (134   | ) |       | (135   | )
|                  | Extension, discoveries and improved recovery, net of related costs           |   |                 | 396  |   |       | 54     |   |       | 63     |  
|                  | Purchase of reserves in place                                                |   |                 | 112  |   |       | 13     |   |       | 680    |  
|                  | Sales of reserves in place                                                   |   |                 | (208 | ) |       |       |   |       | (27    | )
|                  | Net change resulting from revisions in previous quantity estimates           |   |                 | (23  | ) |       | (115   | ) |       | 89     |  
|                  | Accretion of discount                                                        |   |                 | 183  |   |       | 202    |   |       | 376    |  
|                  | Net change in income taxes                                                   |   |                 | (223 | ) |       | (37    | ) |       | 333    |  
|                  | Other significant factors (Exchange rate)                                    |   |                 | (43  | ) |       |       |   |       |       |  
|                 
|End of year       |                                                                              | $ | 2,259           |      | $ | 2,081 |        | $ | 2,719 |        |  
|                 

E-6      ENERPLUS2010 ANNUAL INFORMATION
FORM

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GRAPHIC

Enerplus Corporation

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: 403.298.2211www.enerplus.com

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