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Exhibit 99.1

ANNUAL INFORMATION FORM
For the year ended December 31, 2013

February 21, 2014

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS		1
ABBREVIATIONS AND CONVERSIONS		3
PRESENTATION OF OIL AND GAS RESERVES, RESOURCES AND PRODUCTION INFORMATION		4
	Note to Reader Regarding Oil and Gas Information, Definitions and National Instrument 51-101	4
	Disclosure of Reserves and Production Information	4
	Barrels of Oil and Cubic Feet of Gas Equivalent	5
	Disclosure of Contingent Resources	5
	Interests In Reserves, Production, Wells and Properties	5
	Reserves Categories and Levels of Certainty for Reported Reserves	6
	Development and Production Status	6
	Description of Price and Cost Assumptions	7
PRESENTATION OF FINANCIAL INFORMATION		7
FORWARD-LOOKING STATEMENTS AND INFORMATION		8
CORPORATE STRUCTURE		10
	Enerplus Corporation	10
	Material Subsidiaries	10
	Organizational Structure	10
GENERAL DEVELOPMENT OF THE BUSINESS		11
	Developments in the Past Three Years	11
BUSINESS OF THE CORPORATION		13
	Overview	13
	Summary of Principal Production Locations	14
	Capital Expenditures and Costs Incurred	14
	Exploration and Development Activities	15
	Oil and Natural Gas Wells and Unproved Properties	16
	Description of Properties	16
	Quarterly Production History	21
	Quarterly Netback History	22
	Abandonment and Reclamation Costs	24
	Tax Horizon	24
	Marketing Arrangements and Forward Contracts	25
OIL AND NATURAL GAS RESERVES		27
	Summary of Reserves	27
	Forecast Prices and Costs	30
	Undiscounted Future Net Revenue by Reserves Category	30
	Net Present Value of Future Net Revenue by Reserves Category and Production Group	31
	Estimated Production for Gross Reserves Estimates	32
	Future Development Costs	33
	Reconciliation of Reserves	33
	Undeveloped Reserves	36
	Significant Factors or Uncertainties	36
	Proved and Probable Reserves not on Production	36
SUPPLEMENTAL OPERATIONAL INFORMATION		37
	Safety and Social Responsibility	37
	Insurance	39
	Personnel	39
DESCRIPTION OF CAPITAL STRUCTURE		40
	Common Shares	40
	Preferred Shares	40
	Shareholder Rights Plan	40
	Senior Unsecured Notes	41
	Bank Credit Facility	41
DIVIDENDS AND DISTRIBUTIONS		42
	Dividend Policy and History	42
	Stock Dividend Program	42
INDUSTRY CONDITIONS		43
	Overview	43
	Royalties and Incentives	43
	Land Tenure	44
	Environmental Regulation	44
	Worker Safety	47
RISK FACTORS		48
MARKET FOR SECURITIES		59
DIRECTORS AND OFFICERS		60
	Directors of the Corporation	60
	Officers of the Corporation	61
	Common Share Ownership	62
	Conflicts of Interest	62
	Audit & Risk Management Committee Disclosure	62
LEGAL PROCEEDINGS AND REGULATORY ACTIONS		62
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		63
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS		63
INTERESTS OF EXPERTS		64
TRANSFER AGENT AND REGISTRAR		64
ADDITIONAL INFORMATION		64
APPENDIX A		A-1
APPENDIX B		B-1
APPENDIX C		C-1
APPENDIX D		D-1
APPENDIX E		E-1

Glossary of Terms

Unless the context otherwise requires, in this Annual Information Form, the following terms and abbreviations have the meanings set forth below. Additional terms relating to oil and natural gas reserves, resources and operations have the meanings set forth under "Presentation of Oil and Gas Reserves, Resources and Production Information".

"ABCA" means the Business 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, 2013, the Corporation's $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 by way of a plan of arrangement under the ABCA, pursuant to which, among other things, the former trust units of the Fund, each of which represented an equal undivided beneficial interest in the Fund ("Trust Units"), were exchanged on a one-for-one basis for Common Shares;

"Corporation" means Enerplus Corporation, a corporation amalgamated under the ABCA, and, where the context applies, its subsidiaries, taken as a whole;

"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;

"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;

"IFRS" means International Financial Reporting Standards, as issued by the International Accounting Standards Board, as amended from time to time;

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

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

"McDaniel Reports" means, collectively, the independent engineering evaluations of the Corporation's oil, NGLs and natural gas reserves in Canada and the Corporation's oil, NGLs and natural gas reserves in the United States prepared by McDaniel effective December 31, 2013, utilizing commodity price forecasts of McDaniel as of January 1, 2014;

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

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

"NSAI Reports" means, collectively, the independent engineering evaluations of the Corporation's oil, NGLs, natural gas and shale gas reserves and contingent resources in the Marcellus properties and the natural gas and NGLs reserves in the Jonah field prepared by NSAI effective

ENERPLUS 2013 ANNUAL INFORMATION FORM      1

December 31, 2013, utilizing commodity price forecasts of McDaniel (for internal consistency in the Corporation's reserves reporting) as of January 1, 2014;

"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;

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

"Senior Unsecured Notes" means, as at December 31, 2013, the US$696.6 million principal amount and $70.0 million principal amount of outstanding 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 amended and restated shareholder rights plan agreement between the Corporation and Computershare Trust Company of Canada, as rights agent, dated as of May 10, 2013;

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

"TSX" means the Toronto Stock Exchange; and

"U.S. GAAP" means generally accepted accounting principles in the United States.

2      ENERPLUS 2013 ANNUAL INFORMATION FORM

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
MMcfGE/day	one million cubic feet of natural gas equivalent per day
NGLs	natural gas liquids
NYMEX	the New York Mercantile Exchange
WTI	West Texas Intermediate crude oil that serves as the benchmark crude oil for the NYMEX crude oil contract delivered in Cushing, Oklahoma

Note:

(1)

The Corporation 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, MMcfGEs and BcfGEs. For further information, see "Presentation of Oil and Gas Reserves, Resources and Production Information – Barrels of Oil and Cubic Feet of Gas Equivalent".

In this Annual Information Form, unless otherwise indicated, all dollar amounts are in Canadian dollars and all references to "$" and "CDN$" are to Canadian dollars. References to "US$" are to U.S. dollars. On December 31, 2013, the exchange rate for one U.S. dollar, expressed in Canadian dollars and based upon the noon buying rate of the Bank of Canada, was CDN$1.0636.

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

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

ENERPLUS 2013 ANNUAL INFORMATION FORM      3

Presentation of 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 the Corporation contained in this Annual Information Form contains the information required to be included in the Statement of Reserves Data and Other Oil and Gas Information pursuant to NI 51-101 adopted by the Canadian securities regulatory authorities. Readers should also refer to the Report on Reserves Data by McDaniel attached hereto as Appendix A, the Report on Reserves Data by NSAI attached as Appendix B 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, 2013 and the preparation dates for such information are January 29, 2014 for the McDaniel Reports and January 21, 2014 for the NSAI Reports.

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 oil and natural gas production and realized product prices information is presented on a "company interest" basis (as defined below), unless expressly indicated that it is being presented on a "gross" or "net" basis. "Company interest" means, in relation to the Corporation's interest in production, its working interest (operating or non-operating) share before deduction of royalties, plus the Corporation's royalty interests in production. "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" production of the Corporation may not be comparable to similar measures presented by other issuers, and investors are cautioned that "company interest" production should not be construed as an alternative to "gross" or "net" production calculated in accordance with NI 51-101.

The Corporation's 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 with respect to production information, "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, the Corporation 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. As a consequence of the foregoing, the Corporation's 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 in SEC filings, including contingent resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different

4      ENERPLUS 2013 ANNUAL INFORMATION FORM

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

The Corporation 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, MMcfGEs and BcfGEs. BOEs, MBOEs, MMBOEs, McfGEs, MMcfGEs and BcfGEs 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

DISCLOSURE OF CONTINGENT RESOURCES

In this Annual Information Form, the Corporation has disclosed estimated volumes of economic "contingent resources" which relate to the Corporation's interests in its Fort Berthold property located in North Dakota, its Marcellus shale gas properties located in Pennsylvania, its crude oil waterflood properties located in Alberta and Saskatchewan and its Wilrich natural gas assets located in Alberta.

"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. "Economic" contingent resources are those resources that are currently economically recoverable.

The economic 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 the Corporation – Description of Properties" and "Risk Factors – The Corporation's 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:

"gross" means:

(i)

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

(ii)

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

ENERPLUS 2013 ANNUAL INFORMATION FORM      5

(iii)

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

"net" means:

(i)

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

(ii)

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

(iii)

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

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

RESERVES CATEGORIES AND LEVELS OF CERTAINTY FOR REPORTED RESERVES

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

"reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves may be divided into proved and probable categories according to the degree of certainty associated with the estimates.

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

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

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

•

at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

•

at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

DEVELOPMENT AND PRODUCTION STATUS

Each of the reserves categories reported by the Corporation (proved and probable) may be divided into developed and undeveloped categories:

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

•

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

•

"developed non-producing reserves" are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

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

6      ENERPLUS 2013 ANNUAL INFORMATION FORM

DESCRIPTION OF PRICE AND COST ASSUMPTIONS

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

(i)

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

(ii)

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

Presentation of Financial Information

We have converted our financial reporting from IFRS to U.S. GAAP as (i) over 50% of the book value of our assets (as previously calculated under IFRS) was in the United States, and (ii) over 50% of our Common Shares are held by U.S. residents. Reporting under U.S. GAAP began with our financial statements for the year ended December 31, 2013, with comparatives for 2012 and 2011.

We continue to qualify as a foreign private issuer for our U.S. securities filings as less than 50% of the book value of our assets is in the United States, as calculated under U.S. GAAP as at June 30, 2013. We are required to reassess this annually at the end of our second quarter, and should our U.S. asset book value exceed 50% of our corporate total, we would fail to qualify as a foreign private issuer and would become subject to U.S. domestic filing requirements effective the first day of the following calendar year. See "Risk Factors – Government regulations and required regulatory approvals and compliance may adversely impact the Corporation's operations and result in increased operating and capital costs".

ENERPLUS 2013 ANNUAL INFORMATION FORM      7

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 the Corporation's 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. The Corporation 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 the Corporation 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 quantity of, and future net revenues from, the Corporation's reserves and/or contingent resources;

•

crude oil, NGLs, natural gas and shale gas production levels;

•

commodity prices, foreign currency exchange rates and interest rates;

•

capital expenditure programs, drilling programs, development plans and other future expenditures, including the planned allocation of capital expenditures among the Corporation's properties, the timing of capital expenditures and the sources of funding for such expenditures;

•

supply and demand for oil, NGLs and natural gas;

•

the Corporation's business strategy, including its asset and operational focus;

•

future acquisitions and dispositions and future growth potential;

•

expectations regarding the Corporation's ability to raise capital and to continually add to reserves and/or resources through acquisitions and development;

•

schedules for and timing of certain projects and the Corporation's strategy for growth;

•

the Corporation's future operating and financial results;

•

future abandonment and reclamation costs;

•

future dividends that may be paid by the Corporation;

•

the Corporation's tax pools and the time at which the Corporation may incur certain income or other taxes; and

•

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

The forward-looking information contained in this Annual Information Form reflect several material factors and expectations and assumptions made by the Corporation including, without limitation, that: the Corporation 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; the Corporation's conduct and results of operations will be consistent with its expectations; the Corporation and its industry partners will have the ability to develop the Corporation's 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 the Corporation's 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 the Corporation's operations as planned; and the Corporation's commodity price and other cost assumptions will generally be accurate. The Corporation 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.

The Corporation's 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:

•

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

8      ENERPLUS 2013 ANNUAL INFORMATION FORM

•

actions by governmental or regulatory authorities including different interpretations of applicable laws, treaties or administrative positions as well as changes in income tax laws or changes in royalty regimes and incentive programs relating to the oil and gas industry;

•

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

•

changes in foreign currency exchange rates and interest rates;

•

changes in development plans by the Corporation or third party operators;

•

the ability of the Corporation to access required capital;

•

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

•

liabilities and unexpected events inherent in oil and gas operations, including geological, technical, drilling and processing risks, as well as unforeseen title defects or litigation;

•

actions of and reliance on industry partners;

•

uncertainties associated with estimating reserves and resources;

•

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

•

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

•

constraints on, or the unavailability of, adequate pipeline and transportation capacity to deliver the Corporation's production to market;

•

the Corporation's success at the acquisition, exploitation and development of reserves and resources;

•

changes in general economic, market (including credit market) and business conditions in Canada, North America and worldwide; and

•

changes in tax, environmental, regulatory or other legislation applicable to the Corporation and its operations, and the Corporation's ability to comply with current and future environmental legislation and regulations and other laws and regulations.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in the Corporation's MD&A for the year ended December 31, 2013, 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.

ENERPLUS 2013 ANNUAL INFORMATION FORM      9

Corporate Structure

ENERPLUS CORPORATION

The Corporation was incorporated on August 12, 2010 under the ABCA for the purposes of participating in the Conversion under which the business of Enerplus Resources Fund, as the Corporation's predecessor, was transitioned to the Corporation. 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 – Developments in 2011 – Conversion from an Income Trust to a Corporation". Prior to the Conversion, the business of the Corporation was carried on by the Fund and its subsidiaries as an income trust since 1986.

Effective May 11, 2012, the Corporation amended and restated its articles of amalgamation in connection with the implementation of a stock dividend program. The Corporation amended the rights, privileges, restrictions and conditions in respect of Common Shares to set forth the terms and conditions pursuant to which the Corporation may issue Common Shares as payment of all or any portion of dividends declared on the Common Shares for those shareholders who elect to receive stock dividends instead of cash dividends. See "Description of Capital Structure – Common Shares" and "Dividends and Distributions – Stock Dividend Program".

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. The Corporation also has a U.S. office located at 950 - 17th Street, Suite 2200, Denver, Colorado, 80202-2805. The Common Shares are currently traded on the TSX and the NYSE under the symbol "ERF".

MATERIAL SUBSIDIARIES

As of December 31, 2013, Enerplus USA was the only material subsidiary of Enerplus Corporation. All of the issued and outstanding securities of Enerplus USA are owned by the Corporation.

ORGANIZATIONAL STRUCTURE

The simplified organizational structure of Enerplus Corporation and its material subsidiary as of December 31, 2013 is set forth below.

10      ENERPLUS 2013 ANNUAL INFORMATION FORM

General Development of the Business

DEVELOPMENTS IN THE PAST THREE YEARS

Developments in 2011

CONVERSION FROM AN INCOME TRUST TO A CORPORATION

As a result of legislative changes implemented in June of 2007 that subjected 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, Enerplus completed the Conversion on January 1, 2011 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. As part of the Conversion and related reorganization transactions, unitholders of the Fund exchanged their trust units for Common Shares of the Corporation on a one-for-one basis, the Fund was dissolved, all of the outstanding Trust Units were cancelled and the Corporation continued as the successor issuer to the Fund. The business, directors and management of the Corporation immediately following completion of the Conversion were 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 became a reporting issuer in each of the provinces and territories of Canada.

SALE OF NON-CORE MARCELLUS ACREAGE

In 2011, the Corporation sold approximately 45% of its total Marcellus acreage, consisting of non-core and primarily non-operated acreage in Pennsylvania, Maryland and West Virginia, for approximately $568 million. The Corporation retained approximately 110,000 net acres in the Marcellus shale natural gas play, of which 60% is operated. The sale included approximately 5.4 MMcfGE/day of natural gas production and approximately 23.4 BcfGE of proved plus probable reserves. Proceeds from the sale were used to reduce outstanding debt under the Bank Credit Facility.

Developments in 2012

FINANCINGS AND MONETIZATION ACTIVITIES

On February 8, 2012, the Corporation completed a bought-deal public offering of 14,708,500 Common Shares for aggregate net proceeds of approximately $331 million. The Corporation initially used the net proceeds of this offering to reduce its outstanding indebtedness under the Bank Credit Facility and subsequently utilized such proceeds to fund a portion of its capital expenditure program in 2012.

On May 15, 2012, the Corporation completed a private placement offering of senior unsecured notes in an aggregate principal amount of approximately US$405 million, issued in three tranches, with terms ranging from seven to 12 years and with interest rates of approximately 4.40%. The Corporation used the net proceeds of this offering to reduce its outstanding indebtedness under the Bank Credit Facility. See "Description of Capital Structure – Senior Unsecured Notes".

In August 2012, the Corporation sold all of its common shares in Laricina for net after tax proceeds of approximately $141 million. The net proceeds were used to reduce the Corporation's outstanding indebtedness and subsequently used to fund a portion of its 2012 capital expenditure program. See "Business of the Corporation – Equity Investments".

ACQUISITION OF BAKKEN OIL ASSETS IN MONTANA

On December 17, 2012, the Corporation completed an acquisition of an additional 20% working interest in the Sleeping Giant area in the Elm Coulee field in Richland County in Montana for approximately $118 million, including estimated closing adjustments. This acquisition included approximately 1,550 BOE/day of production and was complementary to the Corporation's existing operations in the Sleeping Giant area. This acquisition consolidated the Corporation's working interest in the subject leases to approximately 90%. For a description of the Corporation's Bakken interests, see "Business of the Corporation – Description of Properties – U.S. Crude Oil Properties".

ENERPLUS 2013 ANNUAL INFORMATION FORM      11

SALE OF NON-CORE MANITOBA ASSETS

On December 19, 2012, the Corporation completed a sale of its crude oil assets located in the Virden/Daly region of Manitoba for approximately $218 million, including estimated closing adjustments. This disposition included approximately 1,600 BOE/day of crude oil production. A portion of the proceeds from the sale were used to fund the acquisition of the Corporation's additional working interest in Bakken oil assets in Montana described above, with the balance utilized to reduce indebtedness under the Bank Credit Facility.

Developments in 2013

ACQUISITION OF ADDITIONAL ASSETS

Property and land acquisitions in 2013 totaled $244.8 million, the most significant consisting of additional interest in the Corporation's core Marcellus properties for $157.9 million in the United States and $34.0 million for additional interest in the Pouce Coupe waterflood property in Canada. See "Business of the Corporation – Description of Properties".

SALE OF NON-CORE ASSETS

In 2013, the Corporation realized proceeds of approximately $365.1 million from disposition activities involving the Corporation's non-core assets located in Canada and the United States. These dispositions included in aggregate approximately 2,700 BOE/day of production. The proceeds from the Corporation's disposition activities were used to fund the Corporation's capital program and to reduce indebtedness under the Bank Credit Facility.

SUCCESSION OF PRESIDENT & CHIEF EXECUTIVE OFFICER

Mr. Gordon J. Kerr, the former President & Chief Executive Officer of the Corporation, retired effective June 30, 2013 as an officer and director of the Corporation. Mr. Ian C. Dundas succeeded Mr. Kerr as the President & Chief Executive Officer and director of the Corporation effective July 1, 2013. Prior thereto, Mr. Dundas held the position of the Executive Vice President & Chief Operating Officer of the Corporation. See "Directors and Officers".

12      ENERPLUS 2013 ANNUAL INFORMATION FORM

Business of the Corporation

OVERVIEW

In 2013, the Corporation executed on its operational programs delivering production growth and funds flow growth, while maintaining capital discipline and a strong balance sheet. The Corporation's 2013 capital spending was focused on its four core areas (as described below), with a 70% weighting to oil projects. Within the United States, the Corporation's capital program focused on the development of its crude oil and natural gas core areas of operation, which includes its North Dakota and Montana crude oil assets in the Williston Basin, and its natural gas interests in northeast Pennsylvania. Capital spending in the United States was approximately 58% of total capital spending in 2013. Capital spending in Canada was directed to its Canadian crude oil waterflood assets, as well as the on-going delineation of its natural gas assets in the Canadian Deep Basin in northwest Alberta.

In addition to capital spending on development and delineation within its core areas, the Corporation continued to concentrate its portfolio through acquisition and divestment activities. In early 2013, the Corporation acquired an incremental 50% working interest in the Pouce Coupe South Boundary Lake waterflood property, increasing the Corporation's interests in this property to approximately 100%. In late 2013, the Corporation also acquired additional working interests in the Marcellus region, bringing its total Marcellus acreage to approximately 60,000 net non-operated acres at December 31, 2013. During 2013, the Corporation also sold certain non-core assets with 2,700 BOE/day of production in Canada and the United States. The Corporation also sold its undeveloped land in the Montney formation in northeast British Columbia in December 2013, with one-half of the proceeds received in January 2014.

The Corporation's oil and natural gas property interests are located in western Canada in the provinces of Alberta, British Columbia and Saskatchewan, and in the United States, primarily in the states of Montana, North Dakota, Pennsylvania, West Virginia and Wyoming. The Corporation's major producing properties generally have related field production facilities and infrastructure to accommodate its production. In general, sales gas infrastructure for the Marcellus region, specifically in northeastern Pennsylvania, is operating at or near capacity. However, infrastructure projects are underway in the region to address these issues, with most projects to be completed by the end of 2017. See "Risk Factors – A decline in the Corporation's ability to market oil and natural gas production could have a material adverse effect on its production levels or on the price that the Corporations receives for production".

Production volumes for the year ended December 31, 2013 from the Corporation's properties consisted of approximately 46% crude oil and NGLs and 54% natural gas, on a BOE basis. The Corporation's 2013 average daily production was 89,793 BOE/day, comprised of 38,250 bbls/day of crude oil, 3,472 bbls/day of NGLs and 288,422 Mcf/day of natural gas, an increase of approximately 9% compared to 2012 average daily production of 82,098 BOE/day, comprised of 36,509 bbls/day of crude oil, 3,627 bbls/day of NGLs and 251,773 Mcf/day of natural gas. The increase in average daily production during 2013 is largely attributable to growth in crude oil production volumes from the Corporation's Fort Berthold properties, as well as increased natural gas production volumes from the Marcellus. The Corporation exited 2013 with average daily production of approximately 99,569 BOE/day in December. Approximately 56% of the Corporation's 2013 production was from Canada, with the remaining 44% from the United States. 67% of its 2013 production was operated by the Corporation; 33% was operated by industry partners.

As at December 31, 2013, the oil and natural gas property interests held by the Corporation were estimated to contain proved plus probable gross reserves of 150,029 Mbbls of light and medium crude oil, 42,066 Mbbls of heavy crude oil, 14,361 Mbbls of NGLs, 564,725 MMcf of natural gas and 600,861 MMcf of shale gas, for a total of 400,720 MBOE. The Corporation's proved reserves represented approximately 65% of total proved plus probable reserves, and approximately 52% of the Corporation's proved plus probable reserves were weighted to crude oil and NGLs. See "Oil and Natural Gas Reserves".

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, 2013, (ii) all production information represents the Corporation's company interest in production from these properties, which includes overriding royalty interests of the Corporation but is calculated before deduction of royalty interests owned by others, and (iii) all references to reserve volumes represent gross reserves using forecast prices and costs. See "Presentation of Oil and Gas Reserves, Resources and Production Information".

ENERPLUS 2013 ANNUAL INFORMATION FORM      13

SUMMARY OF PRINCIPAL PRODUCTION LOCATIONS

During the year ended December 31, 2013, on a BOE basis, approximately 56% of the Corporation's production was derived from Canada (40% from Alberta, 12% from Saskatchewan, and 4% from British Columbia) and approximately 44% from the United States (18% from North Dakota, 18% from Pennsylvania, 8% from Montana, less than 1% from Wyoming and minimal amounts from West Virginia). The following table describes the average daily production from the Corporation's principal producing properties and regions during the year ended December 31, 2013.

2013 Average Daily Production from Principal Properties and Regions

		Products
		Crude Oil
Property/Region		Light and Medium	Heavy	NGLs	Natural Gas	Shale Gas	Total
		(bbls/day)	(bbls/day)	(bbls/day)	(Mcf/day)	(Mcf/day)	(BOE/day)
United States
	Fort Berthold, North Dakota	15,051		643	4,899		16,511
	Marcellus, Pennsylvania					95,273	15,879
	Sleeping Giant, Montana	5,336	–	1	10,168	–	7,031
	Jonah, Wyoming(1)	1	–	27	2,207	–	396
Total United States		20,388	–	671	17,274	95,273	39,817
Canada
	Medicine Hat Glauconitic "C" Unit, Alberta	–	3,926	–	224	–	3,963
	Shackleton, Saskatchewan	–	–	–	22,065	–	3,677
	Tommy Lakes, British Columbia	15	–	418	16,641	–	3,207
	Brooks, Alberta	–	1,929	32	7,447	–	3,202
	Hanlan-Robb, Alberta	–	–	28	18,352	–	3,087
	Freda Lake, Saskatchewan	2,060	–	–	–	–	2,060
	Bantry, Alberta	1	–	–	11,867	–	1,979
	Pembina 5 Way, Alberta	1,304	–	80	1,350	–	1,609
	Giltedge, Alberta	–	1,517	–	104	–	1,535
	Neptune, Saskatchewan	1,455	–	–	–	–	1,455
	Verger, Alberta	–	–	1	7,305	–	1,218
	Pine Creek, Alberta	9	–	263	5,513	–	1,191
	Elmworth, Alberta	–	–	305	4,893	–	1,120
	Hanna Garden, Alberta	–	–	1	6,590	–	1,099
	Joarcam, Alberta	692	–	31	2,164	–	1,085
	Pouce Coupe, Alberta	419	–	62	3,222	–	1,018
	Ansell, Alberta	–	–	85	5,187	–	949
	Other Canada	3,371	1,164	1,495	62,952	–	16,522
Total Canada		9,326	8,536	2,801	175,876	–	49,976
Total		29,714	8,536	3,472	193,150	95,273	89,793

Note:

(1)

Sold on January 14, 2014.

For additional information on the Corporation's oil and natural gas properties, see "Description of Properties".

CAPITAL EXPENDITURES AND COSTS INCURRED

In 2013, the Corporation invested approximately $681 million through its capital program, which was approximately 20% lower than the $853 million in 2012. The Corporation continued to focus the majority of its spending on its core assets, including $315 million on the Fort

14      ENERPLUS 2013 ANNUAL INFORMATION FORM

Berthold crude oil property, $79 million on Marcellus assets, $165 million on Canadian crude oil properties and $89 million on liquids rich deep gas properties in Canada. The foregoing does not include approximately $245 million of expenditures made on property and land acquisitions in 2013, which includes $158 million in the United States and $34 million for additional interest in our Pouce Coupe waterflood property in Canada.

In the financial year ended December 31, 2013, the Corporation made the following expenditures in the categories noted, as prescribed by NI 51-101:

	Property Acquisition Costs					Exploration		Development
		Proved		Unproved		Costs		Costs
		($ in millions)
Canada	$	34.6	$	9.7	$	27.3	$	259.2
United States		131.7		68.8		4.5		390.4
Total	$	166.3	$	78.5	$	31.8	$	649.6

The Corporation expects its 2014 exploration and development capital spending to be approximately $760 million, with over 60% projected to be invested in crude oil projects. The Corporation expects to invest approximately $300 million to $325 million of capital on its Fort Berthold property in the United States, representing approximately 40% of its planned 2014 capital spending. The Corporation intends to finance its 2014 capital expenditure program through a combination of internally-generated cash flow, debt, divestments and proceeds from its stock dividend program. The Corporation will review its 2014 capital investment plans regularly throughout the year in the context of prevailing economic conditions and potential acquisitions, and make adjustments as it deems necessary.

For additional information regarding the Corporation's planned 2014 development capital expenditures for its properties, see "– Description of Properties" below.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table summarizes the number and type of wells that the Corporation drilled or participated in the drilling of for the year ended December 31, 2013, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

	Canada				United States
	Development Wells		Exploratory Wells		Development Wells		Exploratory Wells
Category of Well	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Crude oil wells	62	23	2	–	80	20	–	–
Natural gas wells	14	8	5	2	97	9	–	–
Service wells	30	9	–	–	–	–	–	–
Dry and abandoned wells	–	–	–	–	–	–	–	–
Total	106	40	7	2	177	29	–	–

For a description of the Corporation's planned 2014 development plans and the anticipated sources of funding those plans, see " – Capital Expenditures and Costs Incurred" above and "– Description of Properties" below.

ENERPLUS 2013 ANNUAL INFORMATION FORM      15

OIL AND NATURAL GAS WELLS AND UNPROVED PROPERTIES

The following table summarizes, as at December 31, 2013, the Corporation's interests in producing wells and in non-producing wells which were not producing but which may be capable of production, along with the Corporation's 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
	Oil		Natural Gas		Oil		Natural Gas		(acres)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Canada
Alberta	1,584	860	6,319	3,367	609	283	764	259	681,888	319,474
Saskatchewan	841	159	2,294	2,166	288	40	207	186	316,369	295,420
British Columbia	–	–	241	158	1	–	42	19	80,187	41,999
Ontario									32,882	–
United States
Montana	256	182	1	1	3	1	–	–	2,430	2,430
North Dakota	228	99	–	–	39	8	–	–	3,254	3,254
Pennsylvania	–	–	508	53	–	–	147	16	149,867	49,984
West Virginia	–	–	1	1	–	–	2	2	26,948	26,948
Maryland									286	286
Total	2,909	1,300	9,364	5,746	940	332	1,162	482	1,294,111	739,795

The Corporation expects its rights to explore, develop and exploit on approximately 14,000 net acres of unproved properties in Canada and the United States to expire prior to December 31, 2014 in the ordinary course. The Corporation has no material work commitments on such properties and, where the Corporation determines appropriate, it can extend expiring leases by either making the necessary applications to extend or performing the necessary work.

DESCRIPTION OF PROPERTIES

Outlined below is a description of the Corporation's Canadian and U.S. crude oil and natural gas properties and assets.

Canadian Crude Oil Properties

OVERVIEW

The Corporation's Canadian crude oil production represents approximately 47% of its total crude oil production. This production comes primarily from low decline properties under waterflood, which provide the Corporation with a stable production base and generate free cash flow to support investment in the Corporation's growth plays, as well as its dividend. 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 improving reserve recovery even further. These properties have associated crude oil production installations for emulsion treatment and injection or water disposal. The Canadian crude oil portfolio includes a variety of properties producing from the Cardium, Viking, Boundary Lake, Ratcliffe, Sparky/Lloydminster, Lower Mannville and Glauconitic formations. The Corporation operated over 92% of its Canadian crude oil producing assets as at December 31, 2013.

In 2013, the Corporation's five largest crude oil producing properties were Medicine Hat, Brooks, Freda Lake, Pembina 5 Way and Giltedge, all of which are located in Alberta with the exception of Freda Lake, which is located in Saskatchewan. Production from the Canadian crude oil assets averaged 17,862 BOE/day in 2013, representing approximately 20% of the Corporation's total production for the year. A total of 89.8 MMBOE of proved plus probable reserves were associated with these assets at December 31, 2013, representing 22% of the Corporation's total proved plus probable reserves.

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In 2013, the Corporation invested approximately $165 million on its Canadian crude oil assets with approximately 53% directed to drilling and completions and the remainder on plant and facility enhancements to support future activities. The Corporation drilled 21.1 net crude oil wells in Canada in 2013, with the majority of the drilling in the Ratcliffe, Cardium and Glauconitic formations. In addition, the Corporation advanced work on two enhanced oil recovery ("EOR") projects at Medicine Hat and Giltedge.

The Corporation plans to spend approximately $160 million to $200 million on its Canadian crude oil assets in 2014, focusing at Freda Lake in Saskatchewan and Medicine Hat, Giltedge, Brooks and Pembina in Alberta.

CONTINGENT RESOURCE ESTIMATE

The Corporation has conducted an internal evaluation of the contingent resources associated with a portion of its crude oil waterflood properties which has resulted in a "best estimate" of 58.9 MMBOE being classified as economic contingent resources effective as of December 31, 2013. These contingent resources are economic based on the price and cost assumptions used in the Corporation's 2013 year end reserves evaluations. Improved oil recovery ("IOR") from twelve existing waterfloods through optimization work accounts for approximately 25.7 MMBOE of the total. Approximately 33.2 MMBOE of the total is attributable to EOR projects in the Corporation's Giltedge property and the Medicine Hat Glauconitic "C" Unit where projects are underway. As work proceeds and assessed results continue to support the economic viability of these projects, the Corporation expects that contingent resources will be reclassified as reserves. Although further EOR projects are being contemplated on certain of the Corporation's other Canadian crude oil properties, these have not been fully evaluated and no contingent resource has been assessed. There is no certainty that it will be commercially viable to produce, or that the Corporation 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 the Corporation's ability to make the necessary capital expenditures to develop the properties, reliance on the Corporation's 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 Oil and Gas Reserves, Resources and Production Information – Disclosure of Contingent Resources".

Canadian Natural Gas Properties

OVERVIEW

The Corporation's Canadian natural gas properties are located in Alberta, Saskatchewan and British Columbia. Its primary focus area is within the Deep Basin region where the Corporation holds over 161,000 net acres of high working interest lands. These lands include approximately 76,000 net acres targeting the Stacked Mannville zones (59,000 of which are in the Wilrich formation) and 85,000 net acres in the Willesden Green region of Alberta, targeting the liquids rich Duvernay formation. The Corporation has additional natural gas properties producing from the Nikannassin and Bluesky formations, as well as shallow gas producing assets at Shackleton, in southwest Saskatchewan, and Bantry, Verger, Hanna Garden and Medicine Hat South in Alberta. In 2013, the Corporation directed its capital spending program on the Wilrich and Duvernay formations that it believes provides stronger economic returns than those provided by shallow gas assets or other conventional natural gas assets within its portfolio.

The Corporation invested $84 million in its Canadian natural gas assets in the Deep Basin in 2013. The Corporation continued to delineate its Wilrich position in the Edson and Ansell Minehead areas of Alberta, drilling four wells and bringing three Wilrich wells on-stream during 2013. The Corporation also drilled two vertical Duvernay test wells during 2013 and one horizontal re-entry into a vertical test well. The core analysis from the test wells continues to confirm a range of free condensate across a significant portion of the Corporation's acreage. Further delineation drilling and completions are planned by the Corporation in 2014 to better understand productivity of natural gas and NGLs in this area.

The Corporation's Canadian natural gas production averaged 175,876 Mcf/day in 2013 (exiting 2013 at 161,965 Mcf/day). Proved plus probable reserves totalled 478 BcfGE at December 31, 2013, representing approximately 20% of the Corporation's proved plus probable

ENERPLUS 2013 ANNUAL INFORMATION FORM      17

reserves measured on a BOE basis. The Corporation's largest producing Canadian natural gas properties in 2013 were its Shackleton property in Saskatchewan, its Tommy Lakes property in northern British Columbia and Ansell, Bantry and Verger, all of which are located in Alberta.

The Corporation plans to invest approximately $84 million on both its operated and non-operated liquids-rich deep natural gas assets in 2014. The Corporation intends to continue to delineate the Wilrich formation in the Edson, Ansell, Minehead and Hanlon areas and will also continue its delineation of the Duvernay formation.

CONTINGENT RESOURCE ESTIMATE

The Corporation has conducted an internal evaluation of the contingent resources associated with a portion of Canadian natural gas assets targeting the Wilrich formation. This assessment has resulted in a "best estimate" of 253 BcfGE of economic contingent resources effective as of December 31, 2013. This internal estimate has been audited by McDaniel. The development of these resources is contingent on confirmation of commercial productivity of the undrilled reserves locations and subsequent internal development project approval. The classification of the resources in the Wilrich formation as contingent resources is based on the productivity of the Wilrich formation being similar to the Corporation's adjacent Wilrich producing reserves and offset productivity of competitor wells. These contingent resources have been geologically mapped with significant control from wells drilled for deeper horizons and are economic based on the price and cost assumptions used in the Corporation's 2013 year end reserves evaluations. Significant factors embedded in this estimate include an average recovery of five Bcf per well with ultimate recovery of 50% of the estimated original natural gas in place. There is no certainty that it will be commercially viable to produce, or that the Corporation will produce any portion of the volumes currently classified as "contingent resources". There are a number of inherent risks and contingencies associated with the development of these properties including the Corporation's ability to make the necessary capital expenditures to develop the properties, reliance on the Corporation's industry partners in project development, acquisitions, funding and provisions of services and those other risks and contingencies described above and under "Risk Factors" in this Annual Information Form.

U.S. Crude Oil Properties

OVERVIEW

The Corporation's U.S. crude oil properties are located primarily in the Fort Berthold region of North Dakota and in Richland County, Montana. The Corporation has an approximate 90% average working interest in Fort Berthold with 73,000 net acres of land located primarily in Dunn and McKenzie counties. Production from the Fort Berthold region is from the Bakken and Three Forks formations and consists of light sweet crude oil (42° API) and some associated natural gas and natural gas liquids. Fort Berthold production increased from 14,023 BOE/day at the end of 2012 to approximately 18,000 BOE/day at exit 2013. The Corporation added approximately 25.6 MMBOE of proved plus probable reserves at Fort Berthold field during 2013 for a total of 105.4 MMBOE of proved plus probable reserves associated with this property. The Corporation owns a 90% working interest in the Sleeping Giant property located in the Elm Coulee field in Richland County, Montana. Sleeping Giant is a mature, light oil property which produced 7,031 BOE/day on average in 2013 from the Bakken formation with an average decline of 14%. The Corporation believes there is additional upside potential at Sleeping Giant property through production optimization, refracs, limited infill drilling and the potential for enhanced oil recovery.

Overall, the Corporation's U.S. crude oil and natural gas liquids production averaged approximately 21,059 BOE/day in 2013, representing 50% of the Corporation's 2013 average daily crude oil and liquids production on a BOE basis. The Corporation had 131.2 MMBOE of proved plus probable reserves associated with these assets at December 31, 2013, representing 33% of its total proved plus probable reserves.

The Corporation spent approximately $316 million of capital on its U.S. crude oil assets in 2013, including approximately $315 million at its Fort Berthold property, representing the single largest capital investment in the Corporation's portfolio. In 2013, there were 20.3 net horizontal wells drilled in the Fort Berthold region, targeting both the Bakken and Three Forks formations (consisting of 0.9 short lateral wells and 19.4 long lateral wells) with approximately 24.7 net wells brought on stream during 2013.

In 2014, the Corporation expects to spend between $300 million and $325 million, representing approximately 40% to 43% of its capital budget, on its U.S. crude oil assets with over 95% targeted for the Fort Berthold area. The Corporation plans to drill 20 to 25 net horizontal wells in this region in 2014 with of the majority of these wells planned as long lateral horizontal wells.

18      ENERPLUS 2013 ANNUAL INFORMATION FORM

CONTINGENT RESOURCE ESTIMATE

An evaluation of the Corporation's interests in the Bakken and Three Forks formations at Fort Berthold, North Dakota conducted internally by the Corporation and audited by McDaniel has attributed a "best estimate" of 38.5 MMBOE of economic contingent resources attributable to these formations, effective as of December 31, 2013. As described above, the Corporation converted 7.4 MMBOE of Bakken and 10.6 MMBOE of Three Forks contingent resources into reserves during the year, and added 16.8 MMBOE and 6.2 MMBOE of contingent resources attributable to the Three Forks formation and the Bakken formation, respectively, at December 31, 2013. These contingent resources represent 47.2 net future drilling locations over and above 98 net booked drilling locations identified in the Corporation's booked proved plus probable reserves. These estimates are based primarily upon a drilling density of two wells per drilling spacing unit in each of the Bakken and Three Forks formations. The average expected ultimate recovery per well is estimated at 815 MBOE in this region. These contingent resources are economic using established technologies and under current commodity prices. Given the drilling density to date, the Corporation assumed a non-reserve land utilization of 84% for the Bakken and 92% for the Three Forks formations. The Corporation has approximately 99 net wells currently on production in this area. 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 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 the Corporation will produce, any portion of the volumes currently classified as "contingent resources". The primary contingencies which currently prevent the classification of the Corporation's disclosed contingent resources associated with the Fort Berthold, North Dakota properties as reserves consist of additional delineation drilling to confirm economic productivity in the undeveloped 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 performance of producing wells continues at expected levels. A significant factor related to the estimate is the limited long-term 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 interests in the property including commodity price fluctuations, project costs, the Corporation's 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.

U.S. Natural Gas Properties

The Corporation's U.S. natural gas properties primarily consist of its non-operated Marcellus shale gas interests located in northeastern Pennsylvania where the Corporation holds an interest in approximately 60,000 net acres. The Corporation also holds 23,000 net non-core operated acres in West Virginia and Maryland.

The Corporation's U.S. natural gas production averaged 112,547 Mcf/day in 2013, representing approximately 39% of the Corporation's total natural gas production. As a result of the acquisition of additional working interests in northeastern Pennsylvania during the fourth quarter of 2013, exit production from the Marcellus was approximately 171,083 Mcf/day. Proved plus probable U.S. natural gas reserves were 600.9 Bcf as at December 31, 2013, an increase of 168% from year-end 2012 and represented 25% of the Corporation's total proved plus probable reserves.

In 2013, $79 million was invested in the Corporation's interests in the Marcellus. The Corporation participated in the drilling of a total of approximately 9.3 net wells and a total of approximately 12.7 net wells were brought on stream. The Corporation currently has 54.1 net producing wells in the Marcellus, and 13.3 net wells waiting on completions or tie-in.

The Corporation plans to spend between $110 million and $130 million on drilling projects in its Marcellus properties in the northeast region of Pennsylvania in 2014. The Corporation expects its Marcellus production to grow from 95 MMcf/day in 2013 to over 140 MMcf/day in 2014, which would represent approximately 40% of the Corporation's anticipated natural gas production.

The Corporation has entered into long-term agreements for the gathering, dehydration, processing, compression and transportation of the Corporation's share of production from its Marcellus properties. These agreements are intended to provide the Corporation with cost certainty and direct ties to the northeastern United States natural gas markets through connections with major interstate pipelines.

ENERPLUS 2013 ANNUAL INFORMATION FORM      19

CONTINGENT RESOURCE ESTIMATE

NSAI has also conducted an independent assessment of the contingent resources attributable to the Corporation's interests in the Marcellus properties and has provided a "best estimate" of economic natural gas contingent resources of approximately 1.3 Tcf at December 31, 2013. Approximately 258 Bcf of contingent resources were reclassified as reserves in 2013. However, as a result of reduced estimates of expected ultimate recoveries, the contingent resource estimate was reduced in certain areas and eliminated in others where current economics do not support further development or lease extension of the acreage. The Corporation did see an increase in the contingent resource estimate assigned to its non-operated leases in northeast Pennsylvania due to improved performance. The remaining contingent resources are economic based on the forecast price and cost assumptions used for the Corporation's year-end 2013 reserves evaluations. This estimate assumes a land utilization rate of 65% and that the average well would produce approximately 6.6 Bcf.

There is no certainty that it will be commercially viable to produce, or that the Corporation will produce, any portion of the volumes currently classified as "contingent resources". The primary contingencies which currently prevent the classification of the Corporation's disclosed contingent resources associated with its Marcellus interests as reserves consist of additional delineation drilling to confirm economic productivity in the immediate vicinity of 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 limited access to confidential information of other operators in the Marcellus formation that would support the recognition of reserves on the Corporation's areas of interest. 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 the Corporation's interests in the Marcellus properties including commodity price fluctuations, project costs, the Corporation's ability to make the necessary capital expenditures to develop the properties, reliance on the Corporation's 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 Oil and Gas Reserves, Resources and Production Information – Disclosure of Contingent Resources".

20      ENERPLUS 2013 ANNUAL INFORMATION FORM

QUARTERLY PRODUCTION HISTORY

The following table sets forth the Corporation's average daily production volumes, on a company interest basis, for each fiscal quarter in 2013 and for the entire year, separately for production in Canada and the United States, and in total.

	Year Ended December 31, 2013
Country and Product Type	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Annual
Canada
Light and medium oil (bbls/day)	10,019	9,670	9,230	8,406	9,326
Heavy oil (bbls/day)	9,150	8,694	8,016	8,297	8,536
Total crude oil (bbls/day)	19,169	18,364	17,246	16,703	17,862
Natural gas liquids (bbls/day)	3,116	2,975	2,265	2,858	2,801
Total liquids (bbls/day)	22,285	21,339	19,511	19,561	20,663
Natural gas (Mcf/day)	177,809	186,569	174,169	165,114	175,876
Total Canada (BOE/day)	51,919	52,434	48,539	47,080	49,976
United States
Light and medium oil (bbls/day)	19,152	19,702	21,637	21,028	20,388
Natural gas liquids (bbls/day)	479	522	720	955	671
Total liquids (bbls/day)	19,631	20,224	22,357	21,983	21,059
Natural gas (Mcf/day)	15,113	16,260	17,627	20,033	17,274
Shale gas (Mcf/day)	78,680	88,012	83,368	130,592	95,273
Total United States (BOE/day)	35,264	37,603	39,190	47,087	39,817
Total
Light and medium oil (bbls/day)	29,171	29,372	30,867	29,434	29,714
Heavy oil (bbls/day)	9,150	8,694	8,016	8,297	8,536
Total crude oil (bbls/day)	38,321	38,066	38,883	37,731	38,250
Natural gas liquids (bbls/day)	3,595	3,497	2,985	3,813	3,472
Total liquids (bbls/day)	41,916	41,563	41,868	41,544	41,722
Natural gas (Mcf/day)	192,922	202,829	191,796	185,147	193,150
Shale gas (Mcf/day)	78,680	88,012	83,368	130,592	95,273
Total (BOE/day)	87,183	90,037	87,729	94,167	89,793

ENERPLUS 2013 ANNUAL INFORMATION FORM      21

QUARTERLY NETBACK HISTORY

The following tables set forth the Corporation's average netbacks received for each fiscal quarter in 2013 and for the entire year, separately for production in Canada and the United States, and in total. 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 the Corporation's NGLs production as those costs have been attributed to the applicable wells' principal product type.

	Year Ended December 31, 2013
Light and Medium Crude Oil ($ per bbl)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Annual
Canada
Sales price(1)	$	81.47		$	84.31		$	97.82		$	78.22		$	85.55
Royalties(2)		(12.77	)		(13.73	)		(17.09	)		(14.07	)		(14.39	)
Production costs(3)		(24.22	)		(21.85	)		(21.30	)		(22.69	)		(22.53	)
Netback	$	44.48		$	48.73		$	59.43		$	41.46		$	48.63
United States
Sales price(1)	$	89.06		$	86.58		$	98.04		$	83.89		$	89.52
Royalties(2)		(24.15	)		(23.42	)		(27.80	)		(23.43	)		(24.76	)
Production costs(3)		(7.02	)		(9.23	)		(9.16	)		(8.92	)		(8.62	)
Netback	$	57.89		$	53.93		$	61.08		$	51.54		$	56.14
Total
Sales price(1)	$	86.45		$	85.83		$	97.98		$	82.27		$	88.27
Royalties(2)		(20.24	)		(20.23	)		(24.60	)		(20.76	)		(21.51	)
Production costs(3)		(12.93	)		(13.39	)		(12.79	)		(12.85	)		(12.98	)
Netback	$	53.28		$	52.21		$	60.59		$	48.66		$	53.78

	Year Ended December 31, 2013
Heavy Oil ($ per bbl)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Annual
Canada/Total
Sales price(1)	$	53.24		$	73.22		$	89.86		$	61.78		$	69.07
Royalties(2)		(10.54	)		(15.38	)		(18.87	)		(13.28	)		(14.41	)
Production costs(3)		(11.66	)		(16.26	)		(16.47	)		(18.24	)		(15.58	)
Netback	$	31.04		$	41.58		$	54.52		$	30.26		$	39.08

22      ENERPLUS 2013 ANNUAL INFORMATION FORM

	Year Ended December 31, 2013
Natural Gas Liquids ($ per bbl)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Annual
Canada
Sales price(1)	$	62.33		$	49.05		$	58.64		$	52.39		$	55.51
Royalties(2)		(16.79	)		(13.96	)		(16.50	)		(15.11	)		(15.55	)
Production costs(3)		–			–			–			–			–
Netback	$	45.54		$	35.09		$	42.14		$	37.28		$	39.96
United States
Sales price(1)	$	34.22		$	26.21		$	22.31		$	59.87		$	38.64
Royalties(2)		(8.53	)		(6.57	)		(6.58	)		(8.35	)		(7.56	)
Production costs(3)		–			–			–			–			–
Netback	$	25.69		$	19.64		$	15.73		$	51.52		$	31.08
Total
Sales price(1)	$	58.58		$	45.64		$	49.88		$	54.26		$	52.25
Royalties(2)		(15.69	)		(12.86	)		(14.11	)		(13.42	)		(14.01	)
Production costs(3)		–			–			–			–			–
Netback	$	42.89		$	32.78		$	35.77		$	40.84		$	38.24

	Year Ended December 31, 2013
Natural Gas ($ per Mcf)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Annual
Canada
Sales price(1)	$	2.89		$	3.39		$	2.62		$	3.12		$	3.01
Royalties(2)		(0.09	)		(0.14	)		(0.07	)		(0.07	)		(0.09	)
Production costs(3)		(2.17	)		(1.87	)		(2.01	)		(2.33	)		(2.09	)
Netback	$	0.63		$	1.38		$	0.54		$	0.72		$	0.83
United States
Sales price(1)	$	4.89		$	5.35		$	5.32		$	4.40		$	4.96
Royalties(2)		(1.13	)		(1.21	)		(1.18	)		(1.24	)		(1.19	)
Production costs(3)		–			–			–			–			–
Netback	$	3.76		$	4.14		$	4.14		$	3.16		$	3.77
Total
Sales price(1)	$	3.04		$	3.55		$	2.87		$	3.26		$	3.18
Royalties(2)		(0.17	)		(0.23	)		(0.17	)		(0.19	)		(0.19	)
Production costs(3)		(2.00	)		(1.72	)		(1.82	)		(2.08	)		(1.90	)
Netback	$	0.87		$	1.60		$	0.88		$	0.99		$	1.09

	Year Ended December 31, 2013
Shale Gas ($ per Mcf)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Annual
United States/Total
Sales price(1)	$	3.23		$	4.06		$	3.18		$	3.26		$	3.42
Royalties(2)		(0.68	)		(0.85	)		(0.70	)		(0.68	)		(0.73	)
Production costs(3)		(0.57	)		(0.68	)		(0.70	)		(0.61	)		(0.64	)
Netback	$	1.98		$	2.53		$	1.78		$	1.97		$	2.05

ENERPLUS 2013 ANNUAL INFORMATION FORM      23

	Year Ended December 31, 2013
Total ($ per BOE)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Annual
Canada
Sales price(1)	$	38.89		$	42.67		$	45.69		$	38.97		$	41.56
Royalties(2)		(5.63	)		(6.39	)		(7.40	)		(6.01	)		(6.35	)
Production costs(3)		(14.15	)		(13.38	)		(13.97	)		(15.43	)		(14.21	)
Netback	$	19.11		$	22.90		$	24.32		$	17.53		$	21.00
United States
Sales price(1)	$	58.14		$	57.54		$	63.69		$	49.60		$	56.83
Royalties(2)		(15.24	)		(14.87	)		(17.50	)		(13.05	)		(15.06	)
Production costs(3)		(5.09	)		(6.43	)		(6.54	)		(5.68	)		(5.94	)
Netback	$	37.81		$	36.24		$	39.65		$	30.87		$	35.83
Total
Sales price(1)	$	46.67		$	48.65		$	53.61		$	43.79		$	48.11
Royalties(2)		(9.52	)		(9.93	)		(11.91	)		(9.53	)		(10.21	)
Production costs(3)		(10.37	)		(10.42	)		(10.60	)		(10.52	)		(10.48	)
Netback	$	26.78		$	28.30		$	31.10		$	23.74		$	27.42

Notes:

(1)

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

(2)

Includes production taxes.

(3)

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

ABANDONMENT AND RECLAMATION COSTS

In connection with its operations, the Corporation will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The Corporation budgets for and recognizes as a liability the estimated present value of the future decommissioning liabilities associated with its property, plant and equipment. The Corporation estimates such costs through a model that incorporates data from the Corporation's operating history, industry sources and cost formulas used by Alberta's Energy Resources Conservation Board, together with other operating assumptions. The Corporation expects all of its net wells to incur these costs. The Corporation anticipates the total amount of such costs, net of estimated salvage value for such equipment, to be approximately $721 million on an undiscounted basis and $158 million discounted at 10% in accordance with NI 51-101. The calculations of future net revenue associated with proved plus probable reserves under "Oil and Natural Gas Reserves" in this Annual Information Form exclude approximately $412 million on an undiscounted basis and $66 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, the Corporation anticipates that a total of approximately $81 million on an undiscounted basis and $69 million discounted at 10% will be incurred in respect of abandonment and reclamation costs.

TAX HORIZON

The Corporation is subject to standard applicable corporate income taxes. Within the context of current commodity prices and capital spending plans, the Corporation generally does not expect to be paying material cash taxes in Canada until after 2018 as it estimates it has sufficient tax pools to offset its anticipated taxable income prior to that time. The Corporation expects to pay U.S. cash taxes of approximately 3% to 5% of U.S. cash flow in 2014 and 2015, which is mainly related to Alternative Minimum Tax ("AMT"). AMT is recoverable against regular income taxes payable in the future. These estimates may vary depending on numerous factors, including fluctuations in commodity prices, and the Corporation's capital spending, changes in governing tax laws, and the nature and timing of the Corporation's acquisitions and dispositions. If crude oil and natural gas prices were to strengthen beyond the levels anticipated by the current forward market, the Corporation's tax pools,

24      ENERPLUS 2013 ANNUAL INFORMATION FORM

including the AMT credit, would be utilized more quickly and it may experience higher than expected cash taxes or payment of such taxes in an earlier time period, including regular U.S. income taxes. As a result, the Corporation emphasizes that it is difficult to give guidance on future taxability as it operates within an industry that constantly changes. See "Risk Factors – Changes in income tax and other laws may adversely affect the Corporation and its shareholders."

For additional information, see Notes 2(g) and 13 to the Corporation's audited consolidated financial statements for the year ended December 31, 2013 and the information under the heading "Taxes" in the Corporation's MD&A for the year ended December 31, 2013.

MARKETING ARRANGEMENTS AND FORWARD CONTRACTS

Crude Oil and NGLs

The Corporation's crude oil and NGLs production is marketed to a diverse portfolio of intermediaries and end users generally on 30-day continuously renewing contracts for crude oil and yearly contracts for NGLs whose terms fluctuate with the monthly spot markets. The Corporation received an average price (net of transportation costs but before the effects of commodity derivative instruments) of $88.27/bbl for its light and medium crude oil, $69.07/bbl for its heavy crude oil and $52.25/bbl for its NGLs for the year ended December 31, 2013, compared to $81.16/bbl for its light and medium crude oil, $68.73/bbl for its heavy crude oil and $53.01/bbl for its NGLs for the year ended December 31, 2012.

In Canada, the Corporation sells its crude oil production generally on a 30-day evergreen basis at floating index-based prices. The Corporation typically transports its Canadian crude oil production to its buyers by pipeline or truck. The Corporation has field gathering transportation agreements in place for 2014 to 2016 for approximately 1,500 bbls/day to 2,400 bbls/day of its Saskatchewan production. The Corporation also has pipeline transportation agreements in place for 2016 to 2025 for an average of approximately 900 bbl/day of its Alberta crude oil production. The Corporation typically sells its NGLs production on a one-year contracted basis at floating index-based prices. The Corporation has also contracted NGLs pipeline transportation agreements for an average of approximately 500 BOE/day through 2018.

In the United States, the Corporation sells its crude oil production generally on a negotiated 30-day basis at floating index-based prices. The Corporation transports its U.S. crude oil production to its buyers by pipeline, truck, and/or rail. The Corporation has pipeline transportation agreements in place for 8,500 bbls/day of its U.S. oil production to mid-2016, falling to 7,500 bbls/day through 2018. The Corporation does not directly market its NGLs associated with its U.S. crude oil production. These volumes are marketed on its behalf by midstream companies in North Dakota and Montana.

Natural Gas

In marketing its natural gas production, the Corporation strives for a mix of contracts and customers. In Canada, the Corporation sells its natural gas production at a mix of fixed and floating prices for a variety of terms ranging from spot sales to one year or longer. The Corporation's monthly sales portfolio reflected a relatively equal balance between the daily and monthly AECO market indices in 2013. Approximately 60% of the Corporation's total natural gas production originated in Canada in 2013 and received an average price of $3.01/Mcf during the year.

Approximately 40% of the Corporation's natural gas production originated in the United States. The Corporation sold approximately 60% of its Marcellus production in 2013 on the Transco Leidy Pipeline, with the remaining volumes sold on the Tennessee Gas Pipeline 300 Line in Pennsylvania. The Corporation has firm "must-take" sales contracts for 65 MMcf/day to 70 MMcf/day of natural gas production in the Marcellus with buyers holding pipeline capacity on either of these pipelines. The Corporation received an average price for its U.S. shale natural gas production of US$3.42/Mcf. Approximately 15% of the Corporation's U.S. natural gas production was associated natural gas production from its crude oil operations in North Dakota and Montana. The Corporation does not market these volumes directly, as they are marketed on our behalf by midstream companies. The Corporation received US$4.96/Mcf for this production in 2013 because of the high heat content of the natural gas due to associated liquids.

The Corporation's percentage of 2013 revenues attributable to natural gas (net of transportation costs but before the effects of commodity derivative instruments) was 22% compared to 16% in 2012. The average price received by the Corporation (net of transportation costs but before the effects of commodity derivative instruments) for its natural gas in 2013 was $3.26/Mcf compared to $2.39/Mcf for the year ended December 31, 2012.

ENERPLUS 2013 ANNUAL INFORMATION FORM      25

For 2014, the Corporation has contracts for up to approximately 190 MMcf/day of pipeline capacity, some of it in series, for natural gas in Canada and the United States with contracts that range anywhere from one month to five years. This capacity ensures the Corporation's natural gas production is delivered from the field onto major pipelines and enables the Corporation to sell its production to the local marketplace.

Future Commitments and Forward Contracts

The Corporation 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 the Corporation is sold into the open market at prevailing market prices, which exposes the Corporation to the risks associated with commodity price fluctuations and foreign exchange rates. See "Risk Factors". Information regarding the Corporation's financial instruments is contained in Note 15 to the Corporation's audited consolidated financial statements for the year ended December 31, 2013 and under the headings "Results of Operations – Pricing" and "Results of Operations – Price Risk Management" in the Corporation's MD&A for the year ended December 31, 2013, 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.

26      ENERPLUS 2013 ANNUAL INFORMATION FORM

Oil and Natural Gas Reserves

SUMMARY OF RESERVES

All of the Corporation's reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. Independent reserves evaluations have been conducted on properties comprising approximately 89.5% of the Corporation's total proved plus probable reserves value (discounted at 10%, using forecast prices and costs). McDaniel, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 74% of the net present value (discounted at 10%, using forecast prices and costs) of the Corporation's proved plus probable reserves located in Canada and all of the Corporation's reserves associated with the Corporation's properties located in North Dakota and Montana. The Corporation has evaluated the balance of its Canadian properties using similar evaluation parameters, including the same forecast price, inflation and exchange rate assumptions utilized by McDaniel. McDaniel has reviewed the Corporation's internal evaluation of these properties.

NSAI, independent petroleum consultants based in Dallas, Texas, has evaluated all of the Corporation's reserves associated with the Corporation's properties in Pennsylvania, West Virginia and Wyoming. For consistency in the Corporation's reserves reporting, NSAI used McDaniel's January 1, 2014 forecast prices and inflation rates to prepare their reports. The Corporation used McDaniel's forecast exchange rates set forth below to convert U.S. dollar amounts in the NSAI Report to Canadian dollar amounts for presentation in this Annual Information Form.

The following sections and tables summarize, as at December 31, 2013, the Corporation's 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 columns and rows in the tables may not add due to rounding. For information relating to the changes in the volumes of the Corporation's reserves from December 31, 2012 to December 31, 2013, 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 are presented both before and after deducting income taxes. For additional information, see "Business of the Corporation – 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 the Corporation's 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 Oil and Gas Reserves, Resources and Production Information" in conjunction with the following tables and notes.

The following tables set forth the estimated gross and net reserves volumes and net present value of future net revenue attributable to the Corporation's reserves at December 31, 2013, using forecast price and cost cases. The Corporation has also previously publicly disclosed its reserves on a "company interest" basis (being the gross volumes plus the Corporation's share of royalty interests in reserves), which results in an additional 5.3 MMBOE of proved plus probable reserves attributed to the Corporation. "Company interest" is not a term defined in NI 51-101 and therefore may not be comparable to reserves estimates disclosed by other issuers in accordance with NI 51-101.

ENERPLUS 2013 ANNUAL INFORMATION FORM      27

Summary of Oil and Gas Reserves (Forecast Prices and Costs)
As of December 31, 2013

		Oil and Natural Gas Reserves
		Light & Medium Oil		Heavy Oil		Natural Gas Liquids		Natural Gas		Shale Gas		Total
Reserves Category		Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
		(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)
Proved Developed Producing
	Canada	23,145	20,400	26,689	21,407	5,737	4,200	293,384	262,389	–	–	104,468	89,738
	United States	40,861	33,204	–	–	1,429	1,198	45,262	42,718	212,770	170,423	85,296	69,925
	Total	64,006	53,604	26,689	21,407	7,166	5,398	338,646	305,107	212,770	170,423	189,764	159,663
Proved Developed Non-Producing
	Canada	624	554	136	106	132	94	8,330	6,209	–	–	2,280	1,788
	United States	181	146	–	–	12	10	87	126	72,320	57,893	12,261	9,826
	Total	805	700	136	106	144	104	8,417	6,335	72,320	57,893	14,541	11,614
Proved Undeveloped
	Canada	5,395	4,629	3,980	3,053	334	247	34,484	32,040	–	–	15,456	13,269
	United States	17,484	14,025	–	–	1,088	925	8,731	10,749	126,342	101,084	41,084	33,589
	Total	22,879	18,654	3,980	3,053	1,422	1,172	43,215	42,789	126,342	101,084	56,540	46,858
Total Proved
	Canada	29,163	25,582	30,806	24,566	6,203	4,541	336,199	300,638	–	–	122,204	104,796
	United States	58,526	47,375	–	–	2,529	2,133	54,081	53,593	411,431	329,400	138,640	113,340
	Total	87,689	72,957	30,806	24,566	8,732	6,674	390,280	354,231	411,431	329,400	260,844	218,136
Probable
	Canada	9,662	8,125	11,260	8,588	2,523	1,889	142,103	126,166	–	–	47,129	39,630
	United States	52,678	42,263	–	–	3,106	2,570	32,342	32,601	189,430	151,530	92,746	75,522
	Total	62,340	50,388	11,260	8,588	5,629	4,459	174,445	158,767	189,430	151,530	139,875	115,152
Total Proved Plus Probable
	Canada	38,825	33,708	42,066	33,154	8,726	6,430	478,302	426,804	–	–	169,334	144,426
	United States	111,204	89,637	–	–	5,635	4,704	86,423	86,194	600,861	480,930	231,386	188,862
	Total	150,029	123,345	42,066	33,154	14,361	11,134	564,725	512,998	600,861	480,930	400,720	333,288

28      ENERPLUS 2013 ANNUAL INFORMATION FORM

Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves (Forecast Prices and Costs)
As of December 31, 2013

		Net Present Value of Future Net Revenue Discounted at (%/Year)
		Before Deducting Income Taxes					After Deducting Income Taxes						Unit
Reserves Category		0%	5%	10%	15%	20%	0%	5%	10%	15%	20%		Value(1)
		(in $ millions)											($/BOE)
Proved Developed Producing
	Canada	2,389	1,772	1,422	1,201	1,049	2,161	1,650	1,350	1,155	1,018		$15.85
	United States	2,849	2,048	1,629	1,374	1,202	2,245	1,654	1,339	1,145	1,012		$23.30
	Total	5,238	3,820	3,051	2,575	2,251	4,406	3,304	2,689	2,300	2,030		$19.11
Proved Developed Non-Producing
	Canada	74	54	43	36	31	55	42	34	29	25		$24.05
	United States	225	163	131	111	97	135	97	78	67	59		$13.33
	Total	299	217	174	147	128	190	139	112	96	84		$14.98
Proved Undeveloped
	Canada	434	198	96	43	11	326	142	62	20	(5	)	$7.23
	United States	871	414	216	109	43	523	235	108	38	(6	)	$6.43
	Total	1,305	612	312	152	54	849	377	170	58	(11	)	$6.66
Total Proved
	Canada	2,897	2,025	1,561	1,280	1,091	2,542	1,834	1,446	1,204	1,038		$14.90
	United States	3,945	2,624	1,976	1,594	1,342	2,903	1,986	1,525	1,249	1,065		$17.43
	Total	6,842	4,649	3,537	2,874	2,433	5,445	3,820	2,971	2,453	2,103		$16.21
Probable
	Canada	1,482	740	469	333	254	1,096	544	343	244	186		$11.83
	United States	3,451	1,642	968	641	456	2,071	969	555	359	250		$12.82
	Total	4,933	2,382	1,437	974	710	3,167	1,513	898	603	436		$12.48
Total Proved Plus Probable
	Canada	4,379	2,765	2,030	1,613	1,345	3,638	2,378	1,789	1,448	1,224		$14.06
	United States	7,396	4,266	2,944	2,235	1,798	4,974	2,955	2,080	1,608	1,315		$15.59
	Total	11,775	7,031	4,974	3,848	3,143	8,612	5,333	3,869	3,056	2,539		$14.92

Note:

(1)

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

ENERPLUS 2013 ANNUAL INFORMATION FORM      29

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, 2014 (and utilized by NSAI and by the Corporation in its internal evaluations for consistency in the Corporation's reserves reporting) and the following inflation and exchange rate assumptions:

	Crude Oil								Natural Gas				Natural Gas Liquids
													Edmonton Par Price
Year	WTI(1)		Edmonton Light(2)		Alberta Heavy(3)		Sask Cromer Medium(4)		Alberta AECO Spot Price		U.S. Henry Hub Gas Price		Propanes		Butanes		Condensate & Natural Gasolines		Inflation Rate		Exchange Rate
	($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/MMbtu)		($US/MMbtu)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		(%/year)		($US/$Cdn)
2014	95.00		95.00		67.50		89.30		4.00		4.25		50.20		76.60		102.50		2.0		0.950
2015	95.00		96.50		70.40		90.70		4.25		4.50		50.50		77.80		101.60		2.0		0.950
2016	95.00		97.50		71.20		91.70		4.55		4.75		50.60		78.60		100.60		2.0		0.950
2017	95.00		98.00		71.50		92.10		4.75		5.00		51.30		79.00		101.20		2.0		0.950
2018	95.30		98.30		71.80		92.40		5.00		5.25		52.00		79.20		101.50		2.0		0.950
Thereafter		(5)		(5)		(5)		(5)		(5)		(5)		(5)		(5)		(5)		(5)	0.950

Notes:

(1)

West Texas Intermediate at Cushing Oklahoma 40o API,0.5% sulphur.

(2)

Edmonton Light Sweet 40o API,0.3% sulphur.

(3)

Heavy Crude Oil 12o API at Hardisty, Alberta (after deducting blending costs to reach pipeline quality).

(4)

Midale Cromer Crude Oil 29o API,2.0% sulphur.

(5)

Escalation varies until 2021 and is approximately 2% per year thereafter.

In 2013, the Corporation received a weighted average price (net of transportation costs but before hedging) of $69.07/bbl for heavy crude oil, $88.27/bbl for light and medium crude oil, $52.25/bbl for NGLs and $3.18/Mcf for natural gas and $3.42/Mcf for shale gas.

UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2013, 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	7,887	1,192	3,164	394	240	2,897	355	2,542
	United States	9,005	2,245	2,164	607	44	3,945	1,042	2,903
	Total	16,892	3,437	5,327	1,001	284	6,842	1,397	5,445
Proved Plus Probable Reserves
	Canada	11,304	1,768	4,358	545	254	4,379	741	3,638
	United States	16,474	4,206	3,366	1,451	55	7,396	2,422	4,974
	Total	27,778	5,974	7,724	1,996	309	11,775	3,163	8,612

30      ENERPLUS 2013 ANNUAL INFORMATION FORM

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, 2013, 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)	629	$24.76
	Heavy Oil(1)	597	$24.30
	Natural Gas(2)	335	$1.23
	Shale Gas(4)	n/a	n/a
	Total	1,561
Proved Plus Probable Reserves	Light and Medium Crude Oil(1)	775	$23.13
	Heavy Oil(1)	780	$23.55
	Natural Gas(2)	475	$1.22
	Shale Gas(4)	n/a	n/a
	Total	2,030
United States
Proved Reserves	Light and Medium Crude Oil(1)	1,304	$27.53
	Heavy Oil(1)	n/a	n/a
	Natural Gas(2)	34	$3.69
	Shale Gas(4)	638	$1.94
	Total	1,976
Proved Plus Probable Reserves	Light and Medium Crude Oil(1)	2,104	$23.47
	Heavy Oil(1)	n/a	n/a
	Natural Gas(2)	49	$3.18
	Shale Gas(4)	790	$1.64
	Total	2,944
Total
Proved Reserves	Light and Medium Crude Oil(1)	1,934	$25.56
	Heavy Oil(1)	597	$24.30
	Natural Gas(2)	369	$1.31
	Shale Gas(4)	638	$1.94
	Total	3,537
Proved Plus Probable Reserves	Light and Medium Crude Oil(1)	2,879	$23.38
	Heavy Oil(1)	780	$23.55
	Natural Gas(2)	524	$1.30
	Shale Gas(4)	790	$1.64
	Total	4,974

Notes:

(1)

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

(2)

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

(3)

Calculated using net oil or net gas reserves and forecast price and cost assumptions. Presented in $/bbl for oil and $/Mcf for gas.

(4)

No NGLs are associated with Shale Gas.

ENERPLUS 2013 ANNUAL INFORMATION FORM      31

ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

The volume of total production for the Corporation estimated for 2014 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual 2014 production (including from the Fort Berthold property in the separate table below) may vary from the estimates provided by McDaniel and NSAI as the Corporation's actual development programs, timing and priorities may differ from the forecast of development by McDaniel and NSAI. Columns may not add due to rounding.

		Gross Proved Reserves
		Canada				United States
Product Type		Estimated 2014                      Aggregate Production		Estimated 2014                       Average Daily Production		Estimated 2014                      Aggregate Production		Estimated 2014                       Average Daily Production
Crude Oil
	Light and Medium Crude Oil	4,361	Mbbls	11,947	bbls/day	6,917	Mbbls	18,951	bbls/day
	Heavy Oil	1,653	Mbbls	4,530	bbls/day	–	Mbbls	–	bbls/day
Total Crude Oil		6,014	Mbbls	16,477	bbls/day	6,917	Mbbls	18,951	bbls/day
Natural Gas Liquids		839	Mbbls	2,298	bbls/day	293	Mbbls	804	bbls/day
Total Liquids		6,853	Mbbls	18,774	bbls/day	7,210	Mbbls	19,755	bbls/day
Natural Gas		52,835	MMcf	144,752	Mcf/day	5,835	MMcf	15,987	Mcf/day
Shale Gas		–	MMcf	–	Mcf/day	61,738	MMcf	169,145	Mcf/day
Total		15,658	MBOE	42,900	BOE/day	18,473	MBOE	50,610	BOE/day

		Gross Probable Reserves
		Canada				United States
Product Type		Estimated 2014                      Aggregate Production		Estimated 2014                       Average Daily Production		Estimated 2014                      Aggregate Production		Estimated 2014                       Average Daily Production
Crude Oil
	Light and Medium Crude Oil	195	Mbbls	534	bbls/day	1,316	Mbbls	3,606	bbls/day
	Heavy Oil	108	Mbbls	296	bbls/day	–	Mbbls	–	bbls/day
Total Crude Oil		303	Mbbls	830	bbls/day	1,316	Mbbls	3,606	bbls/day
Natural Gas Liquids		55	Mbbls	151	bbls/day	75	Mbbls	204	bbls/day
Total Liquids		358	Mbbls	981	bbls/day	1,391	Mbbls	3,810	bbls/day
Natural Gas		3,570	MMcf	9,782	Mcf/day	693	MMcf	1,899	Mcf/day
Shale Gas		–	MMcf	–	Mcf/day	2,244	MMcf	6,149	Mcf/day
Total		953	MBOE	2,611	BOE/day	1,880	MBOE	5,151	BOE/day

The following table sets forth McDaniel's estimated 2014 production for the Corporation's Fort Berthold property located in North Dakota, United States, as this field is estimated to account for more than 20% of the above estimate of the Corporation's 2014 production.

		Estimated 2014 Production for Fort Berthold Property
		Gross Proved Reserves				Gross Probable Reserves
Product Type		Estimated 2014                      Aggregate Production		Estimated 2014                             Average Daily Production		Estimated 2014                      Aggregate Production		Estimated 2014                             Average Daily Production
Crude Oil
	Light and Medium Crude Oil	5,293	Mbbls	14,501	bbls/day	1,280	Mbbls	3,505	bbls/day
	Heavy Oil	–	Mbbls	–	bbls/day	–	Mbbls	–	bbls/day
Total Crude Oil		5,293	Mbbls	14,501	bbls/day	1,280	Mbbls	3,505	bbls/day
Natural Gas Liquids		293	Mbbls	804	bbls/day	74	Mbbls	204	bbls/day
Total Liquids		5,586	Mbbls	15,304	bbls/day	1,354	Mbbls	3,709	bbls/day
Natural Gas		2,378	MMcf	6,515	Mcf/day	617	MMcf	1,692	Mcf/day
Shale Gas		–	MMcf	–	Mcf/day	–	MMcf	–	Mcf/day
Total		5,982	MBOE	16,390	BOE/day	1,457	MBOE	3,991	BOE/day

32      ENERPLUS 2013 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. The Corporation intends to fund its development activities through internally generated cash flow and proceeds from the stock dividend program of the Corporation, as well as through debt or the issuance of Common Shares where required. The Corporation does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on the Corporation's disclosed oil and gas reserves or future net revenue attributable to those reserves. For additional information, see "Business of the Corporation – Capital Expenditures and Costs Incurred" and "Business of the Corporation – Exploration and Development Activities".

	Canada				United States
	Proved Reserves		Proved Plus Probable Reserves		Proved Reserves		Proved Plus Probable Reserves
Year	Undiscounted	Discounted at 10%/year	Undiscounted	Discounted at 10%/year	Undiscounted	Discounted at 10%/year	Undiscounted	Discounted at 10%/year
	(in $ millions)
2014	149	145	160	155	330	315	398	379
2015	113	100	154	136	277	240	364	316
2016	31	25	95	78	–	–	344	271
2017	31	23	66	50	–	–	310	222
2018	19	13	19	13	–	–	21	14
Remainder	51	28	51	25	–	–	14	8
Total	394	334	545	458	607	555	1,451	1,209

RECONCILIATION OF RESERVES

Overview

The Corporation's total gross proved plus probable reserves at December 31, 2013 were approximately 400.7 MMBOE, up approximately 17.5% from year-end 2012. The Corporation's gross proved plus probable oil and NGLs reserves remained at 206.5 MMBOE and now represent approximately 52% of total proved plus probable gross reserves, down from 60% at year-end 2012. The Corporation replaced approximately 237% of its 2013 gross production through its exploration and development program, adding 76.2 MMBOE of proved plus probable reserves. Approximately 31% of the additions were oil and NGLs, representing the replacement of 157% the Corporation's 2013 oil and NGLs production. The largest amount of crude oil reserve additions were in the Corporation's Fort Berthold crude oil property in North Dakota. The largest amount of natural gas additions were in the Marcellus shale gas property, as a result of development activities and the acquisition of 143 Bcf of shale gas reserves. Approximately 90% of the acquired reserves in 2013 were attributable to the Marcellus. The Corporation sold 11.4 MMBOE of proved plus probable reserves in 2013, 8.6 MMBOE of which were associated with the disposition of the Corporation's non-core assets. As a result of the weak outlook for natural gas prices, approximately 31 Bcf of natural gas reserves were removed from the Corporation's reserves at year-end. Total proved plus probable natural gas reserves increased by approximately 43% from year-end 2012.

The following tables reconcile the Corporation's gross oil and natural gas reserves from December 31, 2012 to December 31, 2013, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

ENERPLUS 2013 ANNUAL INFORMATION FORM      33

CANADIAN OIL AND GAS RESERVES

Canada	Light & Medium Oil						Heavy Oil						Natural Gas Liquids
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2012	35,688		12,652		48,340		31,509		10,988		42,496		6,786		3,112		9,898
Acquisitions	1,580		290		1,870		–		–		–		19		3		23
Dispositions	(6,612	)	(2,627	)	(9,239	)	–		–		–		(597	)	(213	)	(810	)
Discoveries	–		–		–		–		–		–		–		–		–
Extensions and Improved Recovery	1,504		685		2,189		1,528		1,751		3,279		162		63		225
Economic Factors	491		(13	)	478		55		57		113		(30	)	(17	)	(47	)
Technical Revisions	(136	)	(1,325	)	(1,461	)	820		(1,536	)	(715	)	844		(425	)	419
Production	(3,352	)	–		(3,352	)	(3,107	)	–		(3,107	)	(982	)	–		(982	)
December 31, 2013	29,163		9,662		38,825		30,806		11,260		42,066		6,203		2,523		8,726

Canada	Associated and Non-Associated Gas (Natural Gas)						Shale Gas			Total
Factors	Proved		Probable		Proved Plus Probable		Proved	Probable	Proved Plus Probable	Proved		Probable		Proved Plus Probable
	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)	(MMcf)	(MBOE)		(MBOE)		(MBOE)
December 31, 2012	350,546		168,398		518,944		–	–	–	132,407		54,818		187,225
Acquisitions	1,676		283		1,959		–	–	–	1,879		340		2,219
Dispositions	(5,750	)	(2,059	)	(7,809	)	–	–	–	(8,167	)	(3,184	)	(11,351	)
Discoveries	–		–		–		–	–	–	–		–		–
Extensions and Improved Recovery	23,373		8,340		31,713		–	–	–	7,089		3,890		10,979
Economic Factors	(3,066	)	(908	)	(3,974	)	–	–	–	5		(124	)	(119	)
Technical Revisions	31,502		(31,950	)	(448	)	–	–	–	6,779		(8,611	)	(1,832	)
Production	(62,083	)	–		(62,083	)	–	–	–	(17,788	)	–		(17,788	)
December 31, 2013	336,199		142,103		478,302		–	–	–	122,204		47,129		169,334

UNITED STATES OIL AND GAS RESERVES

United States	Light & Medium Oil						Heavy Oil			Natural Gas Liquids
Factors	Proved		Probable		Proved Plus Probable		Proved	Probable	Proved Plus Probable	Proved		Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2012	56,876		43,081		99,957		–	–	–	2,299		2,215		4,514
Acquisitions	30		681		711		–	–	–	2		40		42
Dispositions	–		–		–		–	–	–	–		–		–
Discoveries	–		–		–		–	–	–	–		–		–
Extensions and Improved Recovery	5,184		14,475		19,659		–	–	–	227		907		1,134
Economic Factors	(556	)	8		(548	)	–	–	–	2		2		4
Technical Revisions	4,368		(5,567	)	(1,199	)	–	–	–	234		(58	)	176
Production	(7,376	)	–		(7,376	)	–	–	–	(235	)	–		(235	)
December 31, 2013	58,526		52,678		111,204		–	–	–	2,529		3,106		5,635

34      ENERPLUS 2013 ANNUAL INFORMATION FORM

(continued)

United States	Associated and Non-Associated Gas (Natural Gas)						Shale Gas						Total
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MBOE)		(MBOE)		(MBOE)
December 31, 2012	47,492		24,266		71,758		146,127		78,373		224,500		91,445		62,402		153,847
Acquisitions	11		266		277		117,668		25,686		143,354		19,645		5,046		24,691
Dispositions	–		–		–		–		–		–		–		–		–
Discoveries	–		–		–		–		–		–		–		–		–
Extensions and Improved Recovery	3,206		7,333		10,539		168,634		89,619		258,253		34,051		31,541		65,591
Economic Factors	(1,125	)	(19	)	(1,144	)	(17,140	)	(8,877	)	(26,017	)	(3,598	)	(1,473	)	(5,071	)
Technical Revisions	9,927		497		10,424		30,917		4,629		35,545		11,408		(4,770	)	6,639
Production	(5,431	)	–		(5,431	)	(34,775	)	–		(34,775	)	(14,312	)	–		(14,312	)
December 31, 2013	54,081		32,342		86,423		411,431		189,430		600,861		138,640		92,746		231,386

TOTAL OIL AND GAS RESERVES

Total	Light & Medium Oil						Heavy Oil						Natural Gas Liquids
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2012	92,564		55,733		148,297		31,509		10,988		42,496		9,085		5,327		14,412
Acquisitions	1,610		971		2,581		–		–		–		21		43		64
Dispositions	(6,612	)	(2,628	)	(9,239	)	–		–		–		(597	)	(213	)	(810	)
Discoveries	–		–		–		–		–		–		–		–		–
Extensions and Improved Recovery	6,688		15,161		21,848		1,528		1,751		3,279		389		970		1,359
Economic Factors	(65	)	(5	)	(70	)	55		57		113		(28	)	(15	)	(43	)
Technical Revisions	4,232		(6,892	)	(2,660	)	820		(1,536	)	(715	)	1,078		(483	)	595
Production	(10,728	)	–		(10,728	)	(3,107	)	–		(3,107	)	(1,217	)	–		(1,217	)
December 31, 2013	87,689		62,340		150,029		30,806		11,260		42,066		8,732		5,629		14,361

Total	Associated and Non-Associated Gas (Natural Gas)						Shale Gas						Total
Factors	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MBOE)		(MBOE)		(MBOE)
December 31, 2012	398,038		192,664		590,702		146,127		78,373		224,500		223,852		117,220		341,072
Acquisitions	1,688		548		2,236		117,668		25,686		143,354		21,524		5,386		26,910
Dispositions	(5,750	)	(2,059	)	(7,809	)	–		–		–		(8,167	)	(3,184	)	(11,351	)
Discoveries	–		–		–		–		–		–		–		–		–
Extensions and Improved Recovery	26,579		15,673		42,251		168,634		89,619		258,253		41,140		35,431		76,570
Economic Factors	(4,191	)	(927	)	(5,118	)	(17,140	)	(8,877	)	(26,017	)	(3,593	)	(1,597	)	(5,189	)
Technical Revisions	41,429		(31,453	)	9,976		30,917		4,629		35,545		18,188		(13,380	)	4,807
Production	(67,513	)	–		(67,513	)	(34,775	)	–		(34,775	)	(32,100	)	–		(32,100	)
December 31, 2013	390,279		174,446		564,725		411,431		189,430		600,861		260,844		139,875		400,720

ENERPLUS 2013 ANNUAL INFORMATION FORM      35

UNDEVELOPED RESERVES

The following tables disclose the volumes of proved undeveloped reserves and probable undeveloped reserves of the Corporation that were first attributed in the years indicated.

Proved Undeveloped Reserves

	Crude Oil
Year(1)	Heavy	Light and Medium	NGLs	Natural Gas	Shale Gas	Total
	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)
Aggregate prior to 2011	6,849	25,017	1,889	272,098	15,747	81,729
2011	885	10,397	572	8,629	25,817	17,595
2012	2,835	6,956	372	2,628	21,876	14,247
2013	1,526	2,335	36	14,905	67,821	17,685

Probable Undeveloped Reserves

	Crude Oil
Year(1)	Heavy	Light & Medium	NGLs	Natural Gas	Shale Gas	Total
	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)
Aggregate prior to 2011	2,616	12,152	975	153,736	60,196	51,398
2011	127	15,178	871	11,515	21,135	21,618
2012	504	15,332	1,054	26,082	55,224	30,441
2013	1,751	12,844	827	11,990	98,491	33,836

Note:

(1)

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

The Corporation 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. The Corporation 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, the Corporation expects this to continue.

SIGNIFICANT FACTORS OR UNCERTAINTIES

A decrease in future commodity prices, and in particular natural gas prices, relative to the forecasts described above under "– Forecast Prices and Costs" could have a negative impact on the Corporation's 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, the Corporation 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 – The Corporation's 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

The Corporation has approximately 16.9 MMBOE of proved plus probable reserves which are capable of production but which, as of December 31, 2013, 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.

36      ENERPLUS 2013 ANNUAL INFORMATION FORM

Supplemental Operational Information

SAFETY AND SOCIAL RESPONSIBILITY

The Corporation strives to develop and operate its oil and natural gas assets in a socially responsible manner and places a high priority on preserving the quality of the environment, protecting the health and safety of its employees, contractors and the public in the communities in which it operates and promoting active and open collaboration with its stakeholders. Additionally, the Corporation actively participates in industry recognized programs that support its sustainable mindset, which expects continuous improvement.

The Corporation has a Health and Safety Policy, an Environment Policy and a Stakeholder Engagement Policy that articulate its commitment to safety and social responsibility ("S&SR"). These policies apply to any activities undertaken by or on behalf of the Corporation.

The Health and Safety Policy articulates the Corporation's commitment to protecting the health and safety of all persons and communities involved in, or affected by, its business activities. The Health and Safety Policy outlines specific commitments, including: (i) striving to ensure no harm to employees, contractors or the public; (ii) complying with relevant acts, codes, laws, regulations, standards and procedures; (iii) providing resources, training and technology to meet health and safety objectives; (iv) consulting with stakeholders on issues related to health and safety; and (v) auditing and inspecting operations as part of continuously improving safe work practices.

The Environment Policy articulates the Corporation's commitment to conducting its activities within the environmental regulations that govern the oil and gas industry within each of its operating jurisdictions and to also proactively mitigate impacts on the environment. The Environment Policy states the Corporation will: (i) consider actions taken in the context of their economic, environmental and social effects; (ii) safeguard the environment with actions, including spill prevention and the mitigation of gas flaring and venting, and be prepared to provide a timely and effective response to unexpected releases of environmental contaminants; (iii) work to reduce waste and improve the efficiency of fresh water use; and (iv) work to improve energy efficiency.

The Stakeholder Engagement Policy articulates the Corporation's commitment to engaging with its stakeholders in a way that fosters mutually beneficial relationships to promote positive economic and social development in its operating areas. The Stakeholder Engagement Policy states the Corporation will: (i) actively and openly collaborate with its stakeholders; (ii) ensure its stakeholders have access to timely, accurate information regarding current or planned operations and projects; (iii) strive to provide local suppliers of goods and services that meet the Corporation's procurement standards with opportunities to participate in its operations and projects; and (iv) develop long-lasting relationships based on trust, mutual respect and common understanding where the Corporation's activities will have a long-lasting impact on the communities in which it operates.

The Safety and Social Responsibility Committee of the Corporation's board of directors is responsible for review of the policies, performance and continuous improvement of the Corporation's Safety and Social Responsibility Management System (the "S&SR System"), ensuring that Corporation's activities are planned and executed in a safe and responsible manner and for review to ensure there are adequate systems in place to support ongoing compliance. Additionally, the committee is responsible for oversight of all results and action plans that have been initiated or proposed by the Corporation with respect to S&SR.

In 2013, a third party comprehensive assessment of the S&SR System was conducted to evaluate the suitability of the S&SR System for the Corporation's operations. This assessment also evaluated the S&SR System against generally accepted best practices within the industry and the international standard for Occupational Health & Safety (ISO18001) and for Environmental Management Systems (ISO14001). In conjunction with the S&SR System, the Corporation utilizes a Sustainability Information Management System to maintain its corporate health and safety and social responsibility performance data.

Health and Safety

The Corporation's employee recordable injury frequency rate increased from 0.40 injuries per 200,000 man hours in 2012 to 0.54 injuries per 200,000 man hours in 2013. The Corporation's contractor total recordable injury frequency decreased from 1.26 injuries per 200,000 man hours in 2012 to 1.23 injuries per 200,000 man hours in 2013. The Corporation's 2013 combined employee/contractor recordable injury frequency rate was 0.96 injuries per 200,000 man hours, unchanged from 2012.

ENERPLUS 2013 ANNUAL INFORMATION FORM      37

Health and safety risks influence workplace practices, operating costs and the establishment of regulatory standards. The Corporation maintains a comprehensive health and safety management system designed to:

•

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

•

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

•

support and participate in the CAPP Responsible Canadian Energy Program to develop and improve safety performance;

•

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

•

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

The health and safety component of the S&SR System is reviewed annually for continuous improvement opportunity. Every three years, the Health and Safety Management System is subject to a third-party audit utilizing the Enform Certificate of Recognition ("COR") Audit Protocol. Third party maintenance audits against the COR Audit Protocol are conducted each year between the Health and Safety Management System audit. In 2012, the Corporation successfully renewed its COR certification.

The Corporation continues to develop and implement prevention measures and safety management program improvements to support its focus and commitment for an injury-free workplace.

Environment

The Corporation 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, the Corporation engages in the following activities:

•

The Corporation supports and participates in the CAPP Responsible Canadian Energy program. The Corporation's participation in this program since its inception demonstrates its commitment to responsible resource development and to continuous improvement in environment, health and safety and social performance;

•

Site abandonment, remediation and reclamation capital expenditures for the Corporation's Canadian properties in 2013 totalled $14.324 million ($10.013 million on operated properties and $4.311 million on non-operated properties). The Corporation's U.S. abandonment capital expenditures totalled $2.282 million (operated and non-operated). The Corporation received 16 reclamation certificates in 2013 by returning sites to that of equivalent land capability;

•

The Corporation conducts annual property reviews in Canada with specific corrosion risk management goals designed to ensure compliance with health, safety and environmental legislation and regulations and in 2013, 83 areas were reviewed;

•

The Corporation continues to manage risk through the implementation of a Pipeline Risk Program and various other pipeline integrity activities including inspection of pipelines at water crossings. The Corporation reviews each pipeline system annually. The Corporation is currently enhancing this program to include a wider range of hazards to identify and mitigate risks to decrease future significant pipeline failure incidents;

•

The Corporation continued its internal facility inspections program and completed 49 inspections at major Canadian facilities in 2013. The average score of environment and regulatory compliance resulting from the internal inspection program in 2013 was 90%. The Corporation also completed five environment and regulatory compliance audits in 2013 at its Canadian facilities and averaged a score of 80% to 90% compliance. In addition, there were 58 well site inspections completed in Canada;

•

The Corporation also continued its internal environmental and regulatory inspections in the United States in 2013. Frequent inspections were conducted at the Corporation's West Virginia, Pennsylvania, Montana and North Dakota sites along with routine drilling rig inspections conducted by field safety personnel; and

•

The Corporation has estimated its direct emissions in 2013 to be approximately 613,397 carbon dioxide equivalent tonnes per year, which is slightly more than the Corporation's direct emissions in 2012 of 612,763 carbon dioxide equivalent tonnes per year. The estimated numbers will be adjusted as additional data becomes available. In 2013, the Corporation completed 59 fugitive emissions infrared surveys at its Canadian facilities to detect losses from leaks and vents and is working to repair identified leaks.

Greenhouse gas regulations have been enacted in British Columbia, Alberta and at the federal level in Canada and the U.S. In British Columbia, the Corporation is subject to the carbon tax introduced in mid-2008. The total carbon tax paid was approximately $967,502 in 2013. In addition, the Corporation is required to report third party verified greenhouse gas emissions annually to the government of British Columbia under the Cap and Trade Act (British Columbia) (the "BCCTA"). The Corporation is not subject to the Canadian greenhouse gas emissions reporting requirement as it does not currently operate facilities above the 50,000 tonnes of carbon dioxide equivalent per year threshold.

38      ENERPLUS 2013 ANNUAL INFORMATION FORM

However, the Corporation is subject to the reporting requirement in the U.S. under the Clean Air Act and the Mandatory Reporting of Greenhouse Gases Rule. The latest of these reports was submitted to the U.S. Environmental Protection Agency on March 31, 2013 for the 2012 operational year. The report for the 2013 operational year will be submitted on March 31, 2014. For more information on the environmental regulation applicable to the Corporation, see "Industry Conditions – Environmental Regulation."

The Corporation endeavours to carry out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice. In particular, with respect to hydraulic fracturing, the Corporation complies with all current Canadian and U.S. regulations and adheres to all CAPP Hydraulic Fracturing Operating Practices. The Corporation proactively employs alternative fracturing technology such as foams, gelled water and reclaimed water to reduce the amount of fresh water required during the fracturing process. The Corporation actively seeks opportunities to collaborate with other area operators to share flowback fluid where feasible through inter-company transfers. Although the Corporation proactively mitigates perceived risks involved in the hydraulic fracturing process, increased capital and operating costs may be incurred if regulations in Canada or the United States impose more stringent compliance requirements surrounding hydraulic fracturing.

The Corporation carries insurance to cover a portion of its property losses, liability and business interruption. Health, safety, environmental and regulatory updates and risks are reviewed regularly by the Safety & Social Responsibility Committee of the Corporation's board of directors. At present, the Corporation believes that it is, and expects 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, the Corporation strives to operate in a socially responsible manner and believes its health, safety and environmental 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, the Corporation identifies key focus areas to support this commitment and sets forth strategic reduction targets. The Corporation believes that by monitoring metrics, identifying areas for improvement and implementing strategies, processes and procedures in those key focus areas, the Corporation can reduce its environmental impact.

INSURANCE

The Corporation 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 the Corporation after considering the perceived risk of loss and appropriate coverage, together with the overall cost. The Corporation 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 the Corporation.

PERSONNEL

As at December 31, 2013, the Corporation employed a total of 707 persons, including full-time benefit and payroll consultants, 575 of whom were in Canada and 132 of whom were in the United States.

ENERPLUS 2013 ANNUAL INFORMATION FORM      39

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 and on the Corporation's EDGAR profile at www.sec.gov on January 2, 2013 and January 5, 2011, respectively.

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 on the Common Shares and to share in the remaining property of the Corporation upon liquidation, dissolution or winding-up.

The articles of the Corporation, as amended and restated on May 11, 2012, contain provisions facilitating payment of dividends on Common Shares through issuance of Common Shares in circumstances where a shareholder of the Corporation validly elects to receive payment of dividends, in whole or in part, in the form of Common Shares (the portion of the dividend payable in Common Shares being referred to in this paragraph as "stock dividends"). In particular, the terms of Common Shares implement procedures for: (i) a shareholder of the Corporation to elect to accept stock dividends; (ii) determining the value and number of Common Shares to be distributed by way of a stock dividend; (iii) accounting for the entitlement of shareholders of the Corporation to fractional Common Shares resulting from stock dividends; (iv) authorizing the sale of Common Shares issued in respect of stock dividends to satisfy tax withholding obligations or to comply with foreign laws or regulations applicable to a shareholder of the Corporation, if required; and (v) payment of cash in respect of fractional Common Shares upon a person ceasing to be a registered shareholder of the Corporation. See "Dividends and Distributions – Stock Dividend Program".

PREFERRED SHARES

There are no Preferred Shares outstanding as of the date of this Annual Information Form. 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.

SHAREHOLDER RIGHTS PLAN

The continuation and amendment and restatement of the Shareholder Rights Plan was approved by shareholders of the Corporation, including by requisite number of the Corporation's "Independent Shareholders" (as defined in the Shareholder Rights Plan), at the annual meeting held on May 10, 2013. The continuation of the Shareholder Rights Plan must next be approved by the Corporation's "Independent Shareholders" at the annual meeting of shareholders of the Corporation to be held 2016, failing which it will expire at the end of such meeting. 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 on May 10, 2013 as a "Security holders documents" on the Corporation's

40      ENERPLUS 2013 ANNUAL INFORMATION FORM

SEDAR profile at www.sedar.com and on the Corporation's EDGAR profile at www.sec.gov, and is available on the Corporation's website at www.enerplus.com under "Corporate Governance".

SENIOR UNSECURED NOTES

Enerplus has issued Senior Unsecured Notes, of which US$696.6 million and CDN$70.0 million principal amounts were outstanding at December 31, 2013. Certain terms of the Senior Unsecured Notes are summarized below:

Issue Date	Original Principal	Remaining Principal	Coupon Rate	Interest Payment Dates	Maturity Date	Term
May 15, 2012	CDN$30 million	CDN$30 million	4.34%	May 15 and November 15	May 15, 2019	Bullet payment on maturity
May 15, 2012	US$20 million	US$20 million	4.40%	May 15 and November 15	May 15, 2022	Bullet payment on maturity
May 15, 2012	US$355 million	US$355 million	4.40%	May 15 and November 15	May 15, 2024	Principal payment required in five equal annual installments beginning May 15, 2020
June 18, 2009	CDN$40 million	CDN$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 five equal annual installments beginning June 18, 2017
October 1, 2003	US$54 million	US$21.6 million	5.46%	April 1 and October 1	October 1, 2015	Two remaining principal payments of equal annual installments required on October 1, 2014 and 2015
June 19, 2002	US$175 million	US$35 million	6.62%	June 19 and December 19	June 19, 2014	Final principal payment of equal annual installment required on June 19, 2014

For additional information see "Material Contracts and Documents Affecting Securityholder Rights".

BANK CREDIT FACILITY

As of December 31, 2013, the Corporation had $214.0 million drawn on a $1.0 billion unsecured, covenant-based credit facility with a syndicate of financial institutions maturing October 31, 2016. For a description of the Bank Credit Facility, see Note 8 to the Corporation's audited consolidated financial statements for the year ended December 31, 2013. See also "Material Contracts and Documents Affecting Securityholder Rights".

ENERPLUS 2013 ANNUAL INFORMATION FORM      41

Dividends and Distributions

DIVIDEND POLICY AND HISTORY

The Corporation's board of directors is responsible for determining the dividend policy of the 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. The dividend record date is on or about the 5^th day of each calendar month (or the immediately preceding business day), and the corresponding dividend payment date is on or about the 20th day of such month. 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 table below sets forth the dividends paid or declared by the Corporation in 2011, 2012, 2013 and January and February of 2014:

Month		2014		2013		2012		2011
January	$	0.09	$	0.09	$	0.18	$	0.18
February		0.09		0.09		0.18		0.18
March		N/A		0.09		0.18		0.18
April		N/A		0.09		0.18		0.18
May		N/A		0.09		0.18		0.18
June		N/A		0.09		0.18		0.18
July		N/A		0.09		0.09		0.18
August		N/A		0.09		0.09		0.18
September		N/A		0.09		0.09		0.18
October		N/A		0.09		0.09		0.18
November		N/A		0.09		0.09		0.18
December		N/A		0.09		0.09		0.18

For 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 the Corporation, see "Risk Factors".

STOCK DIVIDEND PROGRAM

Effective May 11, 2012, the Corporation implemented a stock dividend program pursuant to which shareholders of the Corporation may elect to receive dividends in the form of Common Shares, instead of receiving a cash dividend, issued at a deemed price of 95% of the five day weighted average trading price of the Common Shares on the TSX immediately prior to the applicable dividend payment date. The stock dividend program is available to all shareholders of the Corporation and it replaced the dividend reinvestment plan of the Corporation, which was terminated on May 25, 2012. For additional information on the Corporation's stock dividend program and to obtain copies of the documents related to the program, see the Corporation's website at www.enerplus.com under "Investor Information – Dividends and Tax Info – Stock Dividend Program".

42      ENERPLUS 2013 ANNUAL INFORMATION FORM

Industry Conditions

OVERVIEW

The oil and natural gas industry is subject to extensive controls and regulation governing its operations (including land tenure, exploration, development, production, refining, transportation, 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 the Corporation's 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 the Corporation 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 Corporation owns oil and natural gas properties and related assets in Canada (primarily in Alberta, Saskatchewan and British Columbia) and in Montana, North Dakota, Pennsylvania, West Virginia and Wyoming in the United States. The Corporation's 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. The Corporation's 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.

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. Upon commencement of production, royalties and production taxes are paid in respect of oil and natural gas produced from federal, state and freehold lands. Producers of U.S. Indian leases are required to pay annual rental payments regardless of well production. 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, U.S. Indian 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.

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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) (the "BLM") 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. Substantially all of the leaseholds currently owned by the Corporation in the U.S. have been granted through private individuals.

The majority of the Corporation's operations in North Dakota take place on the Fort Berthold Indian Reservation (the "FBIR") and involve allotee lands, which are lands that are administered by the Bureau of Indian Affairs (the "BIA") but owned by individual band members. As such, these operations are governed by both state and federal regulations. The federal regulations are enforced by U.S. federal departments such as the BIA, the BLM, and the U.S. federal Environmental Protection Agency (the "U.S. EPA"). Federal U.S. regulations may differ significantly from regulations generally applicable to non-federally regulated lands and, as a consequence, have the effect of slowing or halting the Corporation's developments on the FBIR.

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 natural 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/state and local legislation and regulation. These requirements provide for environmental protection and apply restrictions and prohibitions regarding disturbances and releases or emissions of various substances produced or utilized in association with oil and gas industry operations. In addition, legislation and regulation requires that well, pipeline and facility sites are abandoned and reclaimed to the satisfaction of the applicable authorities. 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 these requirements can involve significant expenditures. A breach of such requirements 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 British Columbia, energy projects may be subject to review pursuant to the provisions of the Environmental Assessment Act (British Columbia), which rolls the previous processes for the review of major energy projects into a single environmental assessment process that contemplates public participation in the environmental review. Other environmental protection and management measures, including reclamation, are governed by the Oil and Gas Activities Act (British Columbia) and the Environmental Management Act (British Columbia). In Alberta, environmental compliance is governed by the Environmental Protection and Enhancement Act (Alberta) and the Oil and Gas Conservation Act (Alberta), both of which impose environmental responsibilities on oil and natural gas operators and working interest holders in Alberta and impose penalties for violations, which may be significant. In Saskatchewan, environmental compliance is governed by the Environmental Management and Protection Act (Saskatchewan), the Environmental Assessment Amendment Act (Saskatchewan) and the Oil and Gas Conservation Act (Saskatchewan).

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In 2008, the Province of British Columbia instituted a carbon tax that applies to all fuel users and producers in the province, as well as the BCCTA, which requires third party verified greenhouse gas emissions to be reported annually. See "Supplemental Operational Information – Health, Safety and Environment – Environment". The Province of British Columbia is in discussions with stakeholders and partners of the Western Climate Initiative to develop an Emissions Trading Regulation and an Offsets Regulation under the BCCTA in order to price carbon and to reduce greenhouse gas emissions of regulated emitters through a regional cap and trade program. The Corporation is unable to estimate the future potential compliance costs of these pending regulations without a carbon price or an allocation of emission allowances. However, given the Corporation's current hydrocarbon production levels in British Columbia and a current price of carbon offsets in the marketplace of approximately $15 per tonne of carbon dioxide equivalent, the Corporation does not expect such costs to be material.

The Province of Alberta 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, the Corporation does not operate any facility classed within this large emitter category. 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, the Corporation does not operate any facility classed within this category. Additionally, the Province of Saskatchewan has passed, but not yet proclaimed, the Management and Reduction of Greenhouse Gases Act (Saskatchewan), which would require regulated emitters to report and reduce their greenhouse gas emissions below a prescribed amount below their individual baseline emission level. The Corporation does not operate any facility classed within the regulated emitter category in Saskatchewan based on the 50,000 tonne per year carbon dioxide equivalent emissions threshold.

The Province of Alberta has instituted the Responsible Energy Development Act wherein a new, single regulatory body for upstream oil and gas was established. This single regulator, the Alberta Energy Regulator ("AER"), is a merger of the Energy Resources Conservation Board and the Alberta Environment and Sustainable Resource Development. The AER now has responsibility over the Public Lands Act and the Mines and Minerals Act and will eventually have responsibility over the Water Act and the Environmental Protection and Enhancement Act for oil and gas operations. The intention of this merger is to provide a comprehensive streamlined regulatory process.

In the United States, oil and gas operations are regulated at the federal, state, county and tribal levels of government. At the federal level, well planning and permitting is primarily regulated by the U.S. Department of Interior (BLM and BIA) for operations on public and tribal lands under the Federal Land Policy and Management Act and the National Environmental Policy Act. Environmental conservation and cultural and natural resources protection at the federal level are administered by numerous agencies under multiple statutes.

Environmental planning, permitting and compliance related to media protection and contaminants at the federal level are administered by the U.S. EPA or by various states whose programs have been granted primacy by the U.S. EPA. The U.S. EPA governs federal legislation, including the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act (other than oil and gas exempt wastes), the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act and the Safe Drinking Water Act and Federal Executive Orders.

The Corporation's U.S. operations are subject to various regulations, including those relating to well permits, linear facilities, hydraulic fracturing, underground injection and setbacks (buffers) for environmental protection, including a number of state agencies regulating oil and as activities. In addition to the agencies that directly regulate oil and gas operations, there are other state and local conservation and environmental protection agencies that regulate air quality, state water quality, fish, wildlife, visual quality, transportation, noise, spills and incidents, and transportation.

The U.S. 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 allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. One such regulation that has been issued is the Mandatory Reporting of Greenhouse Gases Rule in which, petroleum and natural gas systems above a certain threshold at an onshore basin level are required to submit an annual greenhouse gas emissions report. The Corporation is subject to this regulation and reporting requirement.

Additional regulations affecting the Corporation's U.S. operations include the following: the approval and promulgation of the Federal Implementation Plan for Oil and Natural Gas Well Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidats and Arikara nations), North Dakota and the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. These regulations

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provide emission control requirements for the Corporation's U.S. assets, as well as increased monitoring, recordkeeping, reporting, and regulatory oversight.

At the request of Congress, in 2011, the U.S. EPA began research under its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The purpose of the study is to assess the potential impacts of hydraulic fracturing on drinking water resources, and to identify the driving factors that may affect the severity and frequency of such impacts. The focus is primarily on hydraulic fracturing of shale formations to extract natural gas, with some study of other oil-and gas-producing formations, including tight sands, and coalbeds. The BLM, which regulates oil and gas operations located on federal and tribal lands, published its latest proposed hydraulic fracturing rules on May 16, 2013. All of the Corporation's operations on the Fort Berthold Indian Reservation are regulated by the BLM. Based on the Corporation's discussion with the BLM, the BLM is currently in the process of sorting through approximately 1.7 million comments received in response to the proposed rule. The BLM has provided no update regarding a schedule for finalizing the rule.

Congress has also initiated various countermeasures aimed at restricting federal agencies' authority to impose new hydraulic fracturing regulations. The political response from Congress is largely in reaction to the BLM's proposed rules, the lingering EPA study and several other federal agency efforts to study the issue. The intent of these countermeasures is to limit federal over-reach on an issue that is considered best managed at the state level.

All U.S. states the Corporation operates in have updated their regulation on hydraulic fracturing disclosure. The requirements fall within two basic categories: (i) design and operational requirements; and (ii) information disclosure. Additionally, Pennsylvania and West Virginia have rules applicable to the tracking of water usage and management of flowback water. North Dakota, Montana, Pennsylvania and West Virginia all require operators to disclose information about the chemicals used in their completions; Montana, Pennsylvania and West Virginia prescribe what chemicals that can be used by operations in their completions. North Dakota requires the posting of this information on the internet-based chemical registry FracFocus. Montana allows operators to use FracFocus in lieu of reporting. The required chemical reporting is not substantially different between the state and FracFocus requirements.

FracFocus is operated by the Ground Water Protection Council, a group of state water officials, and the Interstate Oil and Gas Compact Commission, an association of oil and gas producing states. The online registry was created in 2011, in response, at least in part, to concerns from landowners about the chemical content of fracturing fluids that were being injected into oil and gas wells on their land as well as adjacent properties. FracFocus is widely accepted among the petroleum industry, and the Corporation has determined to utilize the registry in all four states in which it operates. Currently, FracFocus lists over 700 companies as registry participants.

Implementation of more stringent environmental regulations on the Corporation's U.S. operations could affect the capital and operating expenditures and plans for the Corporation's U.S. operations. The Corporation minimizes the potential of these impacts to U.S. operations in many ways, including through the participation and membership in trade organizations, such as North Dakota Petroleum Council, Montana Petroleum Association, West Virginia Oil and Natural Gas Association, Independent Petroleum Association of America and Western Energy Alliance. In addition, the Corporation participates directly in legislative hearings, rulemaking processes, meetings with state officials and local stakeholder groups, and provides both written and verbal comment on proposed legislation and regulation. As in Canada, the Corporation's U.S. operations endeavour to carry out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice.

Subsequent to the International Climate Change meeting in Copenhagen in December 2009 the governments of the United States and Canada committed to a 17% reduction in greenhouse gas emissions by 2020 relative to a 2005 baseline. The Government of Canada is working towards this target on a sector by sector basis but has yet to finalize regulations pertaining to the oil and gas sector. 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 actions and therefore its regulations remain pending.

The Corporation believes that it is, and expects 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. The Corporation anticipates that this compliance may result in increased expenditures of both a capital and expense nature as a result of increasingly stringent

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laws relating to the protection of the environment. The Corporation believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

See "Risk Factors – The Corporation's 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 the Corporation's operations and result in increased operating and capital costs".

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 Corporation. 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 the Corporation's results of operations and financial condition.

The Corporation's 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 the Corporation's 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, including demand for different qualities and types of oil and liquids; (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. Oil and natural gas producers in North America, and particularly Canada, currently receive significantly discounted prices for their production due to constraints on the ability to transport and sell such production to international markets. Additionally, limited natural gas processing capacity may result in producers not realizing the full price for liquids associated with their natural gas production. A failure to resolve such constraints may result in continued reduced commodity prices received by oil and natural gas producers such as the Corporation.

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

The Corporation's expanding portfolio of growth-oriented projects in recent years may expose it to increased operational and financial risks.

As described under "General Development of the Business" and "Business of the Corporation", the Corporation has been adding more growth-oriented projects to its asset portfolio in recent years. These projects include Marcellus shale gas, North Dakota oil, early stage natural gas prospects, including the Duvernay and Wilrich, and undeveloped land positions in Alberta and Saskatchewan Bakken oil. These are earlier stage development projects (and, in certain cases, are more exploration-oriented in nature) than the Corporation has historically participated in and, as a result, there is more risk that the Corporation's expenditures on land, seismic and drilling may not provide economic returns. To the extent the Corporation acquires properties or assets with a higher exploration risk profile, the risk associated with such acquisitions and the future development of those assets carries similar risks.

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) the Corporation's operational and financial performance (including fluctuations in the quantity of the Corporation's oil, NGLs and natural gas production and the sales price that the Corporation 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

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dividend is subject to the discretion of the board of directors of the Corporation, which regularly evaluates the Corporation's dividend policy and the 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 the Corporation's 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 the Corporation 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, the Corporation's 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 the Corporation 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 the Corporation's 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.

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

In the normal course of making capital investments to maintain and expand the Corporation's 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. The Corporation may also dispose of existing properties or assets, including its equity holdings in other issuers, as a means of financing alternative projects or developments. 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, or if the Corporation is unable to dispose of its equity holdings as anticipated, the Corporation's 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 the Corporation 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.

The Corporation's Credit Facilities and any replacement credit facility may not provide sufficient liquidity.

Although the Corporation 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 the Corporation or that additional funds can be obtained as required or on terms which are economically advantageous to the Corporation. The amounts available under the Credit Facilities may not be sufficient for future operations, or the Corporation may not be able to renew its Bank Credit Facility or obtain additional financing on attractive economic terms, if at all. The 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. The Corporation renewed its Bank Credit Facility in 2013, and accordingly it currently expires on October 31, 2016. 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, the Corporation 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 the Corporation to obtain replacement financing or financing on favourable terms, may have a material adverse effect on the Corporation's 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.

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Additionally, in 2013 the Corporation made aggregate principal repayments on its Senior Unsecured Notes of US$45.8 million (CDN$64.6 million including underlying derivatives). The repayment of the Senior Unsecured Notes may require the Corporation to obtain additional financing, which may not be available or may be available on unfavourable terms. The repayment of the Senior Secured Notes also has priority over dividend payments to the Corporation's shareholders.

The Corporation's risk management activities could expose it to losses.

The Corporation may use financial derivative instruments and other hedging mechanisms to limit a portion of the adverse effects resulting from volatility in natural gas and oil commodity prices. To the extent the Corporation hedges its commodity price exposure, it may forego the benefits it would otherwise experience if commodity prices were to increase. In addition, the Corporation's commodity hedging activities could expose it to losses. These losses could occur under various circumstances, including if the other party to the Corporation's hedge does not perform its obligations under the hedge agreement. The Corporation has also entered into hedging arrangements to settle future payments under its equity-based long term incentive programs, which could result in the Corporation suffering losses to the extent the hedged costs of such arrangements exceed the actual costs that would otherwise be payable at the time of settlement.

Fluctuations in foreign currency exchange rates could adversely affect the Corporation's business.

The price that the Corporation receives for a majority of its oil and natural gas is based on U.S.- dollar denominated benchmarks and, therefore, the price that the Corporation 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 U.S. dollar may negatively impact the Corporation's net production revenue by decreasing the Canadian dollars the Corporation receives for a given sale in U.S. dollars while offering limited relief to the Corporation's cost structure, to the extent its costs are incurred in Canadian dollars. The Corporation 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 U.S. dollar. The Corporation may from time-to-time use derivative instruments to manage a portion of its foreign exchange risk. The Corporation currently has in place cross currency and foreign exchange swaps associated with certain of the Senior Unsecured Notes, as described in Note 8 to the Corporation's audited consolidated financial statements for the year ended December 31, 2013.

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

Under U.S. GAAP, the net capitalized cost of oil and gas properties, net of deferred income taxes, is limited to the present value of after-tax future net revenue from proved reserves, discounted at 10%, and based on the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer's fiscal year-end. The amount by which the net capitalized costs exceed the discounted value will be charged to net income. Generally speaking, and particularly in a declining commodity price environment, the use of the trailing twelve month average prices and discounting results in a greater likelihood of a ceiling test write-down under U.S. GAAP than IFRS. While these write-downs would not affect cash flow, the charge to earnings may be viewed unfavourably in the market.

The Corporation may be unable to add or develop additional reserves or resources.

The Corporation 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 the Corporation's 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 the Corporation 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, the Corporation's 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, the Corporation cannot assure that it will be successful in acquiring additional reserves or resources on terms that meet its investment objectives. Without these additions, the Corporation's reserves will deplete and, as a consequence, either its production or the average life of its reserves will decline.

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The Corporation's 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 the Corporation's properties. The actual reserves and resources contained in the Corporation's 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 the Corporation's 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 the Corporation's control. If these factors, assumptions and prices prove to be inaccurate, the Corporation's 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.

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

From time to time, the Corporation 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 the Corporation's ability to realize the anticipated growth opportunities and synergies from combining and integrating the acquired assets and properties into the Corporation's 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 the Corporation's 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 the Corporation apply equally in respect of any future properties or assets that the Corporation may acquire. The Corporation generally conducts certain due diligence in connection with acquisitions, but there can be no assurance that the Corporation will identify all of the potential risks and liabilities related to the subject properties.

When acquiring assets, the Corporation is subject to inherent risks associated with predicting the future performance of those assets. The Corporation makes certain estimates and assumptions respecting the prospectivity and characteristics of the assets it acquires, which may not

ENERPLUS 2013 ANNUAL INFORMATION FORM      51

be realized over time. As such, assets acquired may not possess the value the Corporation attributed to them, which could adversely impact the Corporation's cash flows. To the extent that the Corporation 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 the Corporation's 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 the Corporation's engineers, and these initial assessments may differ significantly from the Corporation's 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 the Corporation, and the Corporation 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 the Corporation's cash flow.

The Corporation may also from time to time dispose of properties and assets. These dispositions may consist of non-core properties or assets or may consist of assets or properties that are being monetized in order to fund alternative projects or development by the Corporation. There can be no assurance that the Corporation 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 the Corporation's results of operations or the trading price of the Common Shares.

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

Higher operating costs for the Corporation's properties will directly decrease the amount of the Corporation's cash flow. Electricity, chemicals, supplies, energy services and labour costs are a few of the Corporation's operating costs that are susceptible to material fluctuation. The level of production from the Corporation's existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond the Corporation's 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 the Corporation's properties are not operated by the Corporation, 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 the Corporation's properties. In 2013, approximately 33% of the Corporation's production was 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 the Corporation may differ from the Corporation's expectations and planning, and may impact the ability and/or cost of the Corporation to finance such expenditures, as well as adversely affect other parts of the Corporation's business and operations. To the extent a third party operator fails to perform these duties properly, faces capital or liquidity constraints or becomes insolvent, the Corporation's results of operations will be negatively impacted.

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

The Corporation is subject to risk of default by the counterparties to the Corporation's contracts.

The Corporation 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 the Corporation's joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to the Corporation may adversely affect the results of operations, cash flows and financial position of the Corporation.

52      ENERPLUS 2013 ANNUAL INFORMATION FORM

Delays in payment for business operations could adversely affect the Corporation.

In addition to the usual delays in payment by purchasers of oil and natural gas to the Corporation or to the operators of the Corporation's properties (and the delays of those operators in remitting payment to the Corporation), 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) blow-outs 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 the Corporation's cash flow and the payment of cash dividends to its shareholders in a given period and expose the Corporation to additional third party credit risks.

The Corporation's 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.

The Corporation's 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, pipeline breaks, rail transportation incidents, craterings, fires, power interruptions and severe weather conditions. The Corporation's 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 the Corporation's property and the property of others. The Corporation cannot fully protect against all of these risks, nor are all of these risks insurable. Although the Corporation carries liability, business interruption and property insurance in respect of such matters, there can be no assurance that insurance will be adequate to cover all losses resulting from such events or that the lost production will be restored in a timely manner. The Corporation 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 the Corporation 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 the Corporation's financial position, including the amount of funds that may be available for dividend payments to shareholders.

In addition, the Corporation's unconventional oil and gas operations (such as the development and production of Bakken oil and shale gas) involve certain additional risks and uncertainties. The drilling and completion of wells and operations on these unconventional assets, and particularly in the Marcellus shale region, present certain challenges that differ from conventional oil and gas operations. Wells on these properties 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 activities required to be undertaken on these unconventional assets may be more extensive and complicated than fracturing the geological formations in the Corporation's other areas of operation and require 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, disputes or litigation may result in a loss of entitlement to production, reserves and resources.

From time to time, the Corporation 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 the Corporation's title to the purchased assets. If this type of defect were to occur, the Corporation's entitlement to the production and reserves (and, if applicable, resources) from the purchased assets could be jeopardized. Furthermore, from time to time, the Corporation may have disputes with industry partners as to ownership rights of certain properties or resources, including with respect to the validity of oil and gas leases held by the Corporation or with respect to the calculation or deduction of royalties payable on the Corporation's production. The existence of title defects or the resolution of disputes may have a material adverse effect on the Corporation or its assets and operations. Furthermore, from time to time, the Corporation or its industry partners may owe one another a contractual, trust related or offset obligations which they may default in satisfying and which may

ENERPLUS 2013 ANNUAL INFORMATION FORM      53

adversely affect the validity of an oil and gas lease in which the Corporation has an interest. The existence of title defects, unsatisfied contractual or trust related obligations, including offset obligations, or the resolution of any disputes with industry partners arising from same, may have a material adverse effect on the Corporation or its assets and operations.

A decline in the Corporation's ability to market oil and natural gas production could have a material adverse effect on its production levels or on the price that the Corporation receives for production.

The Corporation's business depends in part upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and rail transportation and processing facilities to provide access to markets for its production. Canadian federal and provincial, as well as U.S. 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 the Corporation's 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 and North Dakota have become more pronounced as a result of increased drilling and development activities in these regions. Additionally, as exploration and drilling on the Corporation's Marcellus shale gas properties increases, the amount of natural gas and associated NGLs being produced by the Corporation 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, the Corporation's ability to transport its production in these regions may be impaired and could adversely impact the Corporation's production volumes or realized prices from these areas. Oil and natural gas producers in North America, and particularly Canada, currently receive significantly discounted prices for their production due to constraints on the ability to transport and sell such production to international markets. Also, limited natural gas processing capacity may result in producers not realizing the full price for liquids associated with their natural gas production. A failure to resolve such constraints may result in shut-in production or continued reduced commodity prices received by oil and natural gas producers such as the Corporation.

While the third party pipelines and railroad companies generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of pipeline and rail capacity, and unfavourable economic conditions or financing terms may defer or prevent the completion of certain pipeline projects or gathering systems or railway projects 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, the Corporation may have to defer development of or shut in its wells awaiting a pipeline connection or other available transportation capacity and/or sell its production at lower prices than it would otherwise realize or than the Corporation currently projects, which would adversely affect the Corporation's results of and cash flow from operations.

Although the Corporation transports its crude oil production by a diverse mix of pipeline, rail and trucking transportation, in certain regions the Corporation is currently dependent upon only one means of transportation. There may be incremental costs associated with transporting crude oil by rail and there is a risk that access to rail transport may be constrained, dependent upon changes made to existing rail transport regulations. There is a potential for increased government regulations over transporting crude oil and natural gas liquids by rail in Canada and the United States. In addition, the assets of the Corporation are concentrated in specific regions with varying levels of government that could limit or ban the shipping of commodities by truck, pipeline or rail.

The Corporation 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. The Corporation 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 the Corporation. 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 the Corporation's competitors may have greater and more diverse competitive resources to draw upon.

Additionally, as the Corporation became subject to taxation as a Canadian corporation in 2011 as a result of the Conversion from an income trust to a corporation, the Corporation may be at a competitive disadvantage to other industry participants, such as pension resource

54      ENERPLUS 2013 ANNUAL INFORMATION FORM

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.

The Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities.

GENERAL

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 the Corporation's 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 the Corporation, and such costs may be significant.

The Corporation 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, the Corporation's 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.

The Corporation does not establish a separate reclamation fund for the purpose of funding its estimated future environmental and reclamation obligations. The Corporation 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 the Corporation be unable to fully fund the cost of remedying an environmental claim, the Corporation might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

RISKS RELATING TO FRACTURING

The Corporation utilizes horizontal drilling, multi-stage hydraulic fracturing, specially formulated drilling fluids and other technologies in connection with its drilling and completion activities. There has been public concern over the hydraulic fracturing process. Most of these concerns have raised questions regarding the drilling fluids used in the fracturing process, their effect on fresh water aquifers, the use of water in connection with completion operations, the ability of such water to be recycled and induced seismicity associated with fracturing. The U.S. and Canadian federal governments and certain U.S. state and Canadian provincial governments are currently reviewing certain aspects of the scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. At present, most of these governments are primarily engaged in the collection, review and assessment of technical information regarding the hydraulic fracturing process and, with the exception of increased chemical disclosure requirements in certain of the jurisdictions in which the Corporation operates, have not provided specific details with respect to any significant actual, proposed or contemplated changes to the hydraulic fracturing regulatory construct. However, certain environmental and other groups have suggested that additional federal, provincial, territorial, state and municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and may contribute to earthquake activity particularly where in proximity to pre-existing faults. In addition, the U.S. EPA has commenced a study of the potential environmental impacts of hydraulic fracturing, including the impacts on drinking water sources and public health. Further, certain governments in jurisdictions where the Corporation does not currently operate have considered a temporary moratorium on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations.

It is anticipated that federal, provincial and state regulatory frameworks to address concerns related to hydraulic fracturing will continue to emerge. While the Corporation is unable to predict the impact of any potential regulations upon its business, the implementation of new laws, regulations or permitting regulations with respect to water usage or hydraulic fracturing generally could increase the Corporation's costs of

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compliance, operating costs, the risk of litigation and environmental liability, or negatively impact the Corporation's production and prospects, any of which may have a material adverse effect on the Corporation's business, financial condition and results of operations.

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

The expansion of the Corporation's business activities, both geographically and with a new focus on exploration, may draw increased attention from special interest groups opposed to the Corporation, its business or its plans for 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, title and environmental matters.

Changes in tax and other laws and interpretations of those laws may adversely affect the Corporation and its securityholders.

Tax laws, including those 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 securityholders. Additionally, tax authorities having jurisdiction over the Corporation (whether as a result of the Corporation's 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 the Corporation or its securityholders, or may disagree with how the Corporation calculates its income for tax purposes. Additionally, the Corporation may be subject to additional taxation by the tribal authorities having jurisdiction over its Fort Berthold properties. The Corporation has income tax filings that are subject to audit and potential reassessment which may impact the Corporation's tax liability. The Corporation believes appropriate provisions for current and deferred income taxes have been made in its financial statements, however, it is difficult to predict the outcome of audit findings by tax authorities. These findings may increase the amount of its tax liabilities and be detrimental to the Corporation.

Government regulations and required regulatory approvals and compliance may adversely impact the Corporation's 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 the Corporation fails to comply with applicable government regulations or regulatory approvals, the Corporation 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, the Corporation's 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 oil and gas industry, while cities such as Philadelphia and New York have called for bans on drilling in their local watersheds. Similarly, Canadian regulatory bodies have enhanced their oversight of and reporting obligations associated with fracturing procedures. More activity by the Corporation on Indian lands 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 the Corporation.

Additionally, various levels of Canadian and U.S. governments are considering legislation to reduce emissions of greenhouse gases. See "Industry Conditions – Environmental Regulation" for a description of these initiatives. Because the Corporation's operations emit various types of greenhouse gases, such new legislation or regulation could increase the costs related to operating and maintaining the Corporation's 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

56      ENERPLUS 2013 ANNUAL INFORMATION FORM

greenhouse gas emissions and administer and manage a greenhouse gas emissions program. The Corporation is not able at this time to estimate such increased costs; however, they could be significant. Any of the foregoing could have adverse effects on the Corporation's business, financial position, results of operations and prospects.

The Corporation is required to assess its "foreign private issuer" status under U.S. securities laws on an annual basis at the end of its second quarter. If the Corporation were to lose its status as a "foreign private issuer" under U.S. securities laws and is required to fully comply with both U.S. and Canadian securities and accounting requirements applicable to domestic issuers in each country, it may incur additional general and administrative costs of compliance with the increased regulation under each regime.

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

The Corporation 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 the Corporation's activities into new locations may present challenges and risks that the Corporation has not faced in the past, including operational and additional regulatory matters. The Corporation's failure to manage these challenges and risks successfully may adversely affect results of operations and financial condition. In addition, the Corporation's activities are not limited to oil and natural gas production and development, and the Corporation could acquire other energy related assets. Expansion of the Corporation's activities into new areas may present challenges and risks that it has not faced in the past, including dealing with additional regulatory matters. If the Corporation does not manage these challenges and risks successfully, its results of operations and financial condition could be adversely affected.

The loss of the Corporation's key management and other personnel could impact its business.

Shareholders are entirely dependent on the management of the Corporation with respect to the exploration for and development of additional reserves and resources, the acquisition of oil and natural gas properties and assets and the management and administration of all matters relating to the Corporation and its properties and assets. The loss of the services of key individuals could have a detrimental effect on the Corporation. Further, the Corporation's acquisitions and activities in various play types require different skill sets than those needed in developing its mature income-oriented assets. 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 affect 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 the Corporation. See "Directors and Officers – Conflicts of Interest". No assurances can be given that opportunities identified by such persons will be provided to the Corporation.

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 the Corporation 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 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.

The Corporation's information assets and critical infrastructure may be subject to destruction, theft, cyber-attacks or misuse by unauthorized parties.

The Corporation is subject to a variety of information technology and system risks as a part of its normal course operations. Although the Corporation has security measures in place that are designed to mitigate these risks, a breach of its security measures and/or a loss of information could occur and result in a loss of material and confidential information and a disruption to its business activities. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Corporation's business, financial condition and results of operations.

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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 withholding or other taxes on the cash dividends, stock 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 additional taxes on such dividends and these taxes may change from time to time.

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 U.S. 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 U.S. courts of liabilities based solely upon the U.S. 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".

The following table sets forth certain trading information for the Common Shares on the TSX composite index and the United States composite index information for 2013.

	TSX Composite Trading			U.S. Composite Trading
Month	High	Low	Volume	High	Low	Volume
January	$13.71	$12.86	15,221,416	US$13.80	US$13.04	16,762,962
February	$14.01	$12.26	19,404,765	US$13.74	US$12.03	20,008,692
March	$15.50	$13.85	23,643,782	US$15.17	US$13.42	17,355,247
April	$14.93	$12.93	20,546,858	US$14.71	US$12.60	21,020,438
May	$16.95	$13.89	20,660,684	US$16.47	US$13.76	23,054,130
June	$16.13	$14.30	14,214,208	US$15.60	US$13.57	15,772,686
July	$17.27	$15.29	16,913,079	US$16.75	US$14.43	13,828,054
August	$17.90	$16.75	14,419,227	US$17.37	US$16.06	12,166,659
September	$18.35	$17.05	13,574,869	US$17.69	US$16.58	11,083,681
October	$18.43	$16.15	20,145,290	US$17.61	US$15.53	12,863,732
November	$19.83	$17.33	17,792,523	US$18.75	US$16.58	16,712,644
December	$19.96	$18.96	17,520,616	US$18.79	US$17.82	12,103,691

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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
David H. Barr(4)(6) Woodlands, Texas, United States	July 2011	Director of Logan International Inc., a TSX-listed company focused on downhole tools and completion services. Prior thereto, President and Chief Executive Officer and, prior thereto, the Chairman of the board of directors, of Logan International Inc., a TSX-listed oil and gas services company, since March 1, 2011. Prior thereto, Group President of various divisions of Baker Hughes Incorporated, an NYSE-listed oilfield services company.
Edwin V. Dodge(4)(6) Vancouver, British Columbia, Canada	May 2004	Corporate director.
Hilary A. Foulkes Calgary, Alberta, Canada	February 2014	Corporate Director. Prior thereto, Executive Vice President and Chief Operating Officer of Penn West Petroleum Ltd. from 2011 to 2012, a TSX and NYSE-listed oil and gas company. Prior thereto, Senior Vice President of Business Development of Penn West Petroleum Ltd. from 2008 to 2010.
James B. Fraser(5)(6) Polson, Montana, United States	June 2012	Corporate director since June 2012. Prior thereto, Senior Vice President for the shale division of Talisman Energy Inc.'s, a TSX and NYSE-listed oil and gas company, North American operations from September 2008 until April 2012.
Robert B. Hodgins(2)(3)(8) Calgary, Alberta, Canada	November 2007	Independent businessman.
Ian C. Dundas Calgary, Alberta, Canada	July 2013	President & Chief Executive Officer of Enerplus.
Susan M. MacKenzie(4)(5) Calgary, Alberta, Canada	July 2011	Independent consultant since September 2010. Prior thereto, Chief Operating Officer of Oilsands Quest Inc., an NYSE Amex-listed oil sands company through August 2010. Prior thereto, various senior managerial positions with Petro-Canada, a TSX and NYSE-listed integrated oil and gas company prior to its merger with Suncor Energy Inc. in 2009.
Donald J. Nelson(3)(4) Calgary, Alberta, Canada	June 2012	President of Fairway Resources Inc., a private oil and gas consulting services firm.
Douglas R. Martin(1) Calgary, Alberta, Canada	September 2000	Corporate director.
David P. O'Brien(3)(7) Calgary, Alberta, Canada	March 2008	Corporate director.
Elliott Pew(2)(5) Boerne, Texas, United States	September 2010	Director of Common Resources III, L.L.C., a private oil and gas company, since May 2010, and Southwestern Energy Company, an NYSE-listed oil and gas company since July 2012. Prior thereto, a director of Common Resources II, L.L.C., a private oil and gas company, from May 2010 to August 2012. Prior thereto, Chief Operating Officer of Common Resources L.L.C., a private oil and gas company, from March 2007 to May 2010.
Glen D. Roane(2)(3) Canmore, Alberta, Canada	June 2004	Corporate director.
Sheldon B. Steeves(2)(5) Calgary, Alberta, Canada	June 2012	Corporate Director. From January 2001 until April 2012, Chairman and Chief Executive Officer of Echoex Ltd., a junior private oil and gas company.

Notes:

(1)

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

(2)

The Audit & Risk Management Committee is currently comprised of Robert B. Hodgins as Chairman, Elliott Pew, Glen D. Roane and Sheldon B. Steeves.

(3)

The Corporate Governance & Nominating Committee is currently comprised of Glen D. Roane as Chairman, Robert B. Hodgins, Donald J. Nelson and David P. O'Brien.

60      ENERPLUS 2013 ANNUAL INFORMATION FORM

(4)

The Compensation & Human Resources Committee is currently comprised of Susan M. MacKenzie as Chairman, David H. Barr, Edwin V. Dodge and Donald J. Nelson.

(5)

The Reserves Committee is currently comprised of Elliott Pew as Chairman, James B. Fraser, Susan M. MacKenzie and Sheldon B. Steeves.

(6)

The Safety & Social Responsibility Committee is currently comprised of Edwin V. Dodge as Chairman, David H. Barr and James B. Fraser.

(7)

Mr. O'Brien is not standing for re-election at the 2014 annual meeting of shareholders of the Corporation.

(8)

Mr. Hodgins was a director of Skope Energy Inc. ("Skope") in November 2012 when Skope entered into a settlement agreement with Pine Cliff Energy Ltd. ("Pine Cliff") and filed for protection under the Companies' Creditors Arrangement Act (Canada) ("CCAA"). A plan for compromise and arrangement under the CCAA filed by Pine Cliff and Skope was accepted by the Court of Queen's Bench of Alberta on January 15, 2013, received the requisite approval of Skope's creditors on February 15, 2013 and came into effect on February 20, 2013. Mr. Hodgins resigned as a director of Skope on February 19, 2013.

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
Ian C. Dundas Calgary, Alberta, Canada	President & Chief Executive Officer	President & Chief Executive Officer of the Corporation since July 1, 2013. Prior thereto, Executive Vice President & Chief Operating Officer of the Corporation since April 2011. Prior thereto, 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.
Raymond J. Daniels Calgary, Alberta, Canada	Senior Vice President, Operations	Senior Vice President, Operations of the Corporation since May 2012. Prior thereto, Senior Vice President, Canadian Operations of the Corporation since April 2011. Prior thereto, Vice President, Development Services of Enerplus since July 2009. Prior thereto, Vice President, Oil Sands of Enerplus since December 2007.
Eric G. Le Dain Calgary, Alberta, Canada	Senior Vice President, Corporate Development, Commercial	Senior Vice President, Corporate Development, Commercial of the Corporation since July 2013. Prior thereto, Senior Vice President, Strategic Planning, Reserves & Marketing of the Corporation since April 2011. Prior thereto, Vice President, Strategic Planning, Reserves & Marketing of Enerplus since March 2010. Prior thereto, Vice President, Regulatory, Environment and Marketing of Enerplus since December 2008.
Jo-Anne M. Caza Calgary, Alberta, Canada	Vice President, Corporate & Investor Relations	Vice President, Corporate & Investor Relations of Enerplus since January 2008. Prior thereto, Vice President, Investor Relations since 2000.
Jodi Jenson Labrie Calgary, Alberta, Canada	Vice President, Finance	Vice President, Finance of the Corporation since July 2013. Prior thereto, Ms. Jenson Labrie held various positions of increasing responsibility since joining Enerplus in 2003, including Controller, Finance and Senior Manager Planning & Marketing.
Robert A. Kehrig Calgary, Alberta, Canada	Vice President, Business Development & New Plays	Vice President, Business Development & New Plays of the Corporation since February 2013. Prior thereto, Vice President, Resource Development of Enerplus since November 2008.
H. Gordon Love Calgary, Alberta, Canada	Vice President, Technical & Operations Services	Vice President, Technical & Operations Services of the Corporation since July 2012. Prior thereto, Senior Manager, Canadian Operations of the Corporation since May 2011, and, prior thereto, Manager of Well Services of Enerplus since August 2010. Prior to joining Enerplus, Vice President, Operations at Grey Wolf Exploration Inc., a TSX-listed oil and gas company prior to its acquisition by Insignia Energy Ltd. in 2009.
David A. McCoy Calgary, Alberta, Canada	Vice President, General Counsel & Corporate Secretary	Vice President, General Counsel & Corporate Secretary of Enerplus.
Edward L. McLaughlin Denver, Colorado, United States	President, U.S. Operations	President, U.S. Operations of Enerplus since May 2012. Prior thereto, Manager of Land of Enerplus USA since joining Enerplus in November 2011. Prior thereto, Vice President, Corporate Development of Venoco, Inc., an NYSE-listed energy company, from November 2010 to November 2011 and as Manager of Land of FIML Natural Resources, a U.S. private exploration and production company, from June to November 2010. Prior thereto, President of Petro-Canada Resources (USA) Inc., a U.S. subsidiary of Petro-Canada, a TSX and NYSE-listed oil and gas company prior to its merger with Suncor Energy Inc., from September 2003 to June 2010.

ENERPLUS 2013 ANNUAL INFORMATION FORM      61

Christopher M. Stephens Calgary, Alberta, Canada	Vice President, Canadian Assets	Vice President, Canadian Assets of the Corporation since July 2012. Prior thereto, Senior Manager, Canadian Assets of the Corporation since May, and prior thereto, Business Unit Manager since June 2008. Prior thereto, Asset Manager at Burlington Resources Inc., an NYSE-listed oil and gas company prior to its acquisition by ConocoPhillips.
P. Scott Walsh Airdrie, Alberta, Canada	Vice President, Information & Corporate Services	Vice President, Information and Corporate Services of the Corporation since February 2014. Prior thereto, Vice President, Information Systems of the Corporation since April 2011. Prior thereto, Corporate Director, Information Services – Infrastructure and Application & Infrastructure with Suncor Energy Inc. Prior thereto, various management positions with Suncor Energy Inc.
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.
Michael R. Politeski Calgary, Alberta, Canada	Treasurer & Corporate Controller	Treasurer & Corporate Controller of the Corporation since July 2013. Prior thereto, Controller, Finance of the Corporation since August 2012. Prior thereto, Manager Finance of Enerplus since June 2008.

COMMON SHARE OWNERSHIP

As of February 14, 2014, the directors and officers of the Corporation named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 302,639 Common Shares, representing approximately 0.15% of the outstanding Common Shares as of that date.

CONFLICTS OF INTEREST

Certain of the directors and officers named above may be directors or officers of issuers which are in competition with 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 the Canadian securities regulatory authorities is contained in Appendix D to this Annual Information Form.

Legal Proceedings and Regulatory Actions

The Corporation 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 the Corporation's favour, the Corporation does not currently believe that the outcome of any pending or threatened proceedings related to these or other matters, or the amounts which the Corporation may be required to pay by reason thereof, would have a material adverse impact on its financial position, results of operation or liquidity. The Corporation is not and was not during 2013 a party to, and none of the Corporation's property is or was during 2013 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, 2013, and the Corporation has no knowledge of any such proceeding being contemplated.

62      ENERPLUS 2013 ANNUAL INFORMATION FORM

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 the Corporation since January 1, 2011 or in any proposed transaction that has materially affected or is reasonably expected to materially affect Enerplus.

Material Contracts and Documents Affecting the Rights of Securityholders

The Corporation 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, if they were filed prior to the January 1, 2011 Conversion, and 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, if they were filed on or after the January 1, 2011 Conversion:

1.

Amended and Restated Bank Credit Facility (November 5, 2012) and the First Amending Agreement relating thereto (January 13, 2014);

2.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2002, together with the First Amendment and Second Amendment (March 18, 2008);

3.

Third Amendment to the Note Purchase Agreement for the Senior Unsecured Notes issued in 2002 (SEDAR – November 10, 2010; EDGAR – November 12, 2010);

4.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2003, together with the First Amendment (March 18, 2008);

5.

Second Amendment to the Note Purchase Agreement for the Senior Unsecured Notes issued in 2003 (SEDAR – November 10, 2010; EDGAR – November 12, 2010);

6.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2009 (SEDAR – June 23, 2009; EDGAR – June 25, 2009); and

7.

Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2012 (SEDAR – May 23, 2012; EDGAR – May 24, 2012).

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:

1.

the Articles of Amalgamation (January 2, 2013) and bylaws of the Corporation (January 5, 2011); and

2.

the Shareholder Rights Plan, as described under "Description of Share Capital – Shareholder Rights Plan" (May 10, 2013).

ENERPLUS 2013 ANNUAL INFORMATION FORM      63

Interests of Experts

McDaniel prepared the McDaniel Reports in respect of certain reserves attributable to the Corporation's oil and natural gas properties in Canada and the western United States, a summary of which is contained in this Annual Information Form, and reviewed certain reserves evaluated internally by the Corporation. McDaniel also audited the estimate of contingent resources attributable to the Corporation's 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 Form of the Canadian securities regulatory authorities) of McDaniel, as a group, beneficially owned, directly or indirectly, less than 1% of the outstanding Common Shares. NSAI prepared the NSAI Reports in respect of the reserves and contingent resources attributable to the Corporation's interests in the Marcellus and Jonah properties, a summary of which is contained in this Annual Information Form. As of the dates of the NSAI Reports, the designated professionals of NSAI, as a group, beneficially owned, directly or indirectly, less than 1% of the outstanding Common Shares.

The independent auditor of the Corporation is Deloitte LLP ("Deloitte"), Independent Registered Chartered Accountants, Calgary, Canada. Deloitte has confirmed that it is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta, the rules of the United States Securities Act of 1933, as amended, and the applicable rules and regulations adopted by the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board (United States).

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, will be contained in the Corporation's information circular and proxy statement with respect to its 2014 annual meeting of shareholders. Furthermore, additional financial information relating to the Corporation is provided in the Corporation's audited consolidated financial statements and MD&A for the year ended December 31, 2013. 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.

64      ENERPLUS 2013 ANNUAL INFORMATION FORM

APPENDIX A

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

January 29, 2014

Enerplus Corporation
3000, 333 - 7^th Avenue SW
Calgary, Alberta
T2P 2Z1

Attention: The Board of Directors of Enerplus Corporation

Re:

Form 51-101F2

Report on Reserves Data by an Independent Qualified Reserves Evaluator of Enerplus Corporation

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

1.

We have evaluated and reviewed the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, estimated using forecast prices and costs.

2.

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

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

3.

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

4.

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated and reviewed by us, for the year ended December 31, 2013, and identifies the respective portions thereof that we have evaluated, reviewed and reported on to the Company's management:

Preparation Date of	Location of	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate)
Evaluation Report	Reserves	Audited	Evaluated	Reviewed	Total
		(in $ thousands)
January 29, 2014	Canada	–	$1,507,938.5	$522,061.5	$2,030,000.0
January 29, 2014	United States	–	US$1,999,491.6	US$                –	US$1,999,491.6

5.

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

6.

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

7.

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

Executed as to our report referred to above:

MCDANIEL & ASSOCIATES CONSULTANTS LTD.

"signed by P.A. Welch" P.A. Welch, P. Eng.
President & Managing Director

Calgary, Alberta
January 29, 2014

ENERPLUS 2013 ANNUAL INFORMATION FORM      A-1

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"):

1.

We have evaluated the Company's reserves data as at December 31, 2013, for certain properties located in Pennsylvania, West Virginia and Wyoming. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, estimated using forecast prices and costs.

2.

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

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

3.

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

4.

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management:

Independent Qualified	Description and Preparation	Location of Reserves (Country or Foreign	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate)
Reserves Evaluator or Auditor	Date of Evaluation Report	Geographic Area)	Audited		Evaluated	Reviewed		Total
			(US$ thousands)
Netherland, Sewell &	January 21, 2014	United States	Nil	$	796,895.1	Nil	$	796,895.1
Associates, Inc.

5.

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

6.

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

7.

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

Executed as to our report referred to above:

NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
Dallas, Texas USA
February 12, 2014

"signed by C.H. (Scott) Rees III" C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer

ENERPLUS 2013 ANNUAL INFORMATION FORM      B-1

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 "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation'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, 2013, estimated using forecast prices and costs.

Independent qualified reserves evaluators have evaluated and reviewed the Corporation'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 Corporation has:

(a)

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

(b)

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

(c)

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

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

(a)

the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b)

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

(c)

the content and filing of this report.

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

ENERPLUS CORPORATION
"Ian C. Dundas"	"Eric G. Le Dain"
Ian C. Dundas President & Chief Executive Officer	Eric G. Le Dain Senior Vice President, Corporate Development, Commercial
"Elliott Pew"	"Sheldon B. Steeves"
Elliott Pew Director	Sheldon B. Steeves Director

February 21, 2014

ENERPLUS 2013 ANNUAL INFORMATION FORM      C-1

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), Elliott Pew, Glen D. Roane and Sheldon B. Steeves. 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) •  Caracal Energy Inc. (oil and gas exploration and development company) •  Contact Exploration Inc. (oil and gas exploration and production company) •  Cub Energy Inc. (oil and gas exploration and production company) •  MEG Energy Corp. (oil sands company) •  MGM Energy Corp. (oil and gas exploration and production company) •  Santonia Energy Inc. (oil and gas exploration and production 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. Elliott Pew (B.Sc., M.A.) (Director since September 2010) Other Public Directorships •  Southwestern Energy Company (oil and gas exploration and production company)	Mr. Pew is a director of Common Resources II, LLC (a private oil and gas company) located in The Woodlands, Texas. Mr. Pew was a co-founder of Common Resources LLC and served as its Chief Operating Officer from March 2007 until it was sold in May 2010. Prior thereto, Mr. Pew was Executive Vice President, Exploration of Newfield Exploration Company (an NYSE-listed oil and gas company) from November 2004 to December 2006 where he led the company's diversification efforts onshore in the late 1990s in addition to leading the company's exploration program, including the formation of the deep water Gulf of Mexico business unit. Prior thereto, Mr. Pew was Senior Vice President, Exploration with American Exploration Corp. Mr. Pew is a Geology graduate of Franklin and Marshall College and holds an M.A. in Geology from the University of Texas.

ENERPLUS 2013 ANNUAL INFORMATION FORM      D-1

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) •  SilverWillow 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. Mr. Roane also holds the ICD.D designation from the Institute of Corporate Directors.

Mr. Sheldon B. Steeves (B.Sc. (Geology)) (Director since June 2012) Other Public Directorships •  Tamarack Valley Energy Ltd.

Mr. Steeves has over 37 years of experience in the North American oil and gas industry and is currently a director of Tamarack Valley Energy Ltd., a TSX-listed Canadian oil and gas company with operations in the Western Canadian Sedimentary Basin. From January 2001 until April 2012, Mr. Steeves was Chairman and Chief Executive Officer of Echoex Ltd., a junior oil and gas private company focused on greenfield organic growth in Western Canada. Mr. Steeves spent over 15 years at Renaissance Energy Ltd., where he was appointed Chief Operating Officer in 1997. Mr. Steeves holds a Bachelor of Science in Geology from the University of Calgary.

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 in 2013 and 2012 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 described above is compatible with maintaining that firm's independence from the Corporation.

E. EXTERNAL AUDITOR SERVICE FEES

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

		2013		2012
		(in $ thousands)
Audit fees(1)	$	965.9	$	809.9
Audit-related fees(2)		–		–
Tax fees(3)		500.5		678.9
All other fees(4)		–		–
	$	1,466.4	$	1,488.8

Notes:

(1)

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

(2)

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

(3)

Tax fees were for tax compliance, tax advice and tax planning.

(4)

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

D-2      ENERPLUS 2013 ANNUAL INFORMATION FORM

Audit & Risk Management Committee Charter

I       AUTHORITY

The Audit & Risk Management Committee (the "Committee") of the Board of Directors (the "Board") of the 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 Chair of the Committee shall be designated by the Board, provided that if the Board does not so designate a Chair, the members of the Committee, by majority vote, may designate a Chair. 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.

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:

1.

financial reporting and continuous disclosure of the Corporation;

2.

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

3.

evaluating and monitoring the performance and independence of the Corporation's external auditors; and

4.

monitoring the manner in which the business risks of the Corporation are being identified and managed.

The Committee shall report to the Board on a regular basis with regard to such matters. The Committee has direct responsibility to recommend the appointment of the external auditors and approve 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 judgement as a member of the Committee. All members of the Committee shall be financially literate and at least one member of the Committee shall have accounting or related financial management expertise – "literate" or "literacy" and "expertise" as defined by applicable securities legislation. Members are encouraged to enhance their understanding of current issues through means of their preference.

IV    MEETINGS OF THE COMMITTEE

The Committee shall meet with such frequency and at such intervals as it shall determine is necessary to carry out its duties and responsibilities. As part of its purpose to foster open communications, the Committee shall meet at least quarterly with management and the Corporation's external auditors in separate executive sessions to discuss any matters that the Committee or each of these groups, or persons, believes should be discussed privately. The Chair 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

ENERPLUS 2013 ANNUAL INFORMATION FORM      D-3

others to attend its meetings (or portions thereof) and to provide pertinent information as necessary. The Committee shall maintain minutes of its meetings and records relating to those meetings and the Committee's activities and provide copies of such minutes to the Board.

V     DUTIES AND ACTIVITIES OF THE COMMITTEE

Evaluating and monitoring the performance and independence of external auditors

1.

Make recommendations to the Board on the appointment of external auditors of the Corporation;

2.

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

3.

Review the performance of the external auditors and make recommendations to the Board regarding their replacement when circumstances warrant. The review shall take into consideration the evaluation made by management of the external auditors' performance and shall include.

a)

Review annually the external auditors' quality control, any material issues raised by the most recent quality control review, or peer review, of the firm, or any inquiry or investigation by governmental or professional authorities of the firm within the preceding five years, and any steps taken to deal with such issues;

b)

Obtain assurances from the external auditors that the audit was conducted in accordance with Canadian and U.S. generally accepted auditing standards; and

c)

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

4.

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

a)

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

b)

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

c)

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

d)

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

e)

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

f)

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

g)

having a private meeting with the external auditors at every quarterly Committee meeting; and

h)

obtaining annually the auditors' views on competency and integrity of the audit committee and senior financial executives;

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

5.

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

6.

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

7.

Review the appropriateness of management's representation letter transmitted to the external auditors;

8.

Receipt of certifications from the CEO and CFO;

D-4      ENERPLUS 2013 ANNUAL INFORMATION FORM

9.

Review with management the adequacy of annual and quarterly financial statements and disclosure in the management discussion and analysis and press release and recommend approval to the Board:

a)

obtain satisfactory answers from management following the review of the annual and quarterly financial statements and management discussion and analysis and press release;

b)

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

c)

the methods used to account for significant unusual transactions;

d)

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

e)

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

f)

significant recorded and unrecorded audit adjustments;

g)

any material accounting issues among management and the external auditors;

h)

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

i)

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

j)

significant legal, compliance or regulatory matters that may have a material effect on the financial statements or the business of the organization (including material notices to, or inquiries received from, governmental agencies); and

k)

receive the report from the Reserves Committee over the appropriateness of reported reserves and resources.

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

10.

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

11.

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

12.

Review with management the Corporation's internal controls, and evaluate whether the Corporation is operating in accordance with prescribed policies and procedures;

13.

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

14.

Review the management disclosure and oversight Committee's CEO and CFO certification processes to ensure compliance with U.S. and Canadian requirements.

15.

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

16.

Review annually the report of the external auditor on the Corporation's internal controls over financial reporting describing any material issues raised by the most recent reviews of internal controls and management information systems or by any inquiry or investigation by governmental or professional authorities and any recommendations made and steps taken to deal with any such issues;

Review of Business Risks

17.

Review with management the process followed to do the Corporation's risk assessment and the policies to monitor, mitigate and report such business risks;

ENERPLUS 2013 ANNUAL INFORMATION FORM      D-5

Other Matters

18.

Review of appointment or dismissal of senior financial executives;

19.

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

20.

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

21.

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

22.

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

23.

Once a year, the Committee reviews the adequacy of its Charter and brings to the attention of the Board required changes, if any, for approval. The Committee is also reviewed annually by the Corporate Governance and Nominating Committee, which reports its findings to the Board.

While the Committee has the duties and responsibilities set forth in this Charter, the Committee is not responsible for planning or conducting the audit or for determining whether the 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.

D-6      ENERPLUS 2013 ANNUAL INFORMATION FORM

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' 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"). The standard requires the use of a 12 month average price to estimate proved reserves calculated as the unweighted arithmetic average of first-day-of-the-month prices within the 12 month period prior to the end of the reporting period. Proved reserves and production volumes are presented net of royalties in accordance with U.S. protocol.

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 and natural gas liquids 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 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, 2013, 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.

Enerplus' December 31, 2013 proved crude oil, natural gas and natural gas liquids reserves are located in western Canada, primarily in Alberta, British Columbia and Saskatchewan, as well as in the United States, primarily in the states of Montana, North Dakota, Pennsylvania, West

ENERPLUS 2013 ANNUAL INFORMATION FORM      E-1

Virginia and Wyoming. 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		Oil and NGLs		Natural Gas		Oil and NGLs		Natural Gas
	(Mbbls)		(MMcf)		(Mbbls)		(MMcf)		(Mbbls)		(MMcf)
Proved Developed and Undeveloped
Reserves at December 31, 2010	74,069		389,353		24,770		78,032		98,839		467,385
Purchases of reserves in place	101		–		–		–		101		–
Sales of reserves in place	(639	)	(845	)	(10	)	(8,110	)	(649	)	(8,955	)
Discoveries and extensions	3,617		14,016		9,627		44,988		13,244		59,004
Revisions of previous estimates	764		813		2,834		(3,310	)	3,598		(2,497	)
Improved recovery	203		2,715		–		–		203		2,715
Production	(6,810	)	(70,498	)	(3,335	)	(9,820	)	(10,145	)	(80,318	)
Proved Developed and Undeveloped
Reserves at December 31, 2011	71,305		335,554		33,886		101,780		105,191		437,334
Purchases of reserves in place	1		–		2,871		5,232		2,872		5,232
Sales of reserves in place	(5,625	)	(1,321	)	(41	)	(39	)	(5,667	)	(1,360	)
Discoveries and extensions	2,396		1,545		9,172		44,357		11,568		45,902
Revisions of previous estimates	1,372		(77,050	)	5,706		3,794		7,079		(73,256	)
Improved recovery	51		350		–		–		51		350
Production	(7,247	)	(65,072	)	(4,825	)	(15,991	)	(12,072	)	(81,063	)
Proved Developed and Undeveloped
Reserves at December 31, 2012	62,253		194,005		46,769		139,133		109,022		333,139
Purchases of reserves in place	1,472		1,482		25		92,395		1,497		93,877
Sales of reserves in place	(649	)	(704	)	–		–		(649	)	(704	)
Discoveries and extensions	2,617		9,944		4,174		140,142		6,791		150,086
Revisions of previous estimates	(4,025	)	83,307		2,811		36,223		(1,214	)	119,530
Improved recovery	–		–		–		–		–		–
Production	(6,198	)	(56,760	)	(6,199	)	(33,114	)	(12,397	)	(89,874	)
Proved Developed and Undeveloped
Reserves at December 31, 2013	55,470		231,274		47,580		374,779		103,050		606,053
Proved Developed Reserves
December 31, 2010	68,906		372,550		18,570		56,653		87,476		429,203
December 31, 2011	65,353		325,520		21,650		69,071		87,003		394,591
December 31, 2012	54,148		187,418		29,612		106,770		83,761		294,188
December 31, 2013	47,316		225,005		33,147		265,464		80,463		490,469

E-2      ENERPLUS 2013 ANNUAL INFORMATION FORM

B.    CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

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

		2013			2012			2011
		(in $ thousands)
Capitalized costs(1)	$	11,481,207		$	10,658,923		$	9,920,024
Less accumulated depletion, depreciation and amortization		(9,061,063	)		(8,343,224	)		(7,051,427	)
Net capitalized costs	$	2,420,144		$	2,315,599		$	2,868,597

Note:

(1)

Includes capitalized costs of proved and unproved properties.

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

Costs incurred in connection with oil and gas producing activities are presented in the table below. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties, including an allocation of purchase price on business combinations that result in property acquisitions. A carry commitment relating to Enerplus' 2009 Marcellus acquisition was included in that years' property acquisition costs in its entirety and as a result property acquisition costs in subsequent years have excluded 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. 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, 2013
			Canada		United States		Total
			(in $ thousands)
Acquisition of properties:
	Proved	$	34,632	$	131,654	$	166,286
	Unproved		9,737		68,814		78,551
Exploration costs			27,312		4,481		31,793
Development costs			259,230		390,413		649,643
Asset retirement costs			31,536		5,097		36,633
		$	362,447	$	600,459	$	962,906

		For the Year Ended December 31, 2012
			Canada		United States		Total
			(in $ thousands)
Acquisition of properties:
	Proved	$	–	$	117,625	$	117,625
	Unproved		13,581		17,131		30,712
Exploration costs			38,388		24,083		62,471
Development costs			216,968		574,016		790,984
Asset retirement costs			24,516		5,060		29,576
		$	293,453	$	737,915	$	1,031,368

ENERPLUS 2013 ANNUAL INFORMATION FORM      E-3

		For the Year Ended December 31, 2011
			Canada		United States		Total
			(in $ thousands)
Acquisition of properties:
	Proved	$	2,100	$	–	$	2,100
	Unproved		110,382		33,173		143,555
Exploration costs			37,591		73,030		110,621
Development costs			288,669		467,203		755,872
Asset retirement costs			23,199		6,206		29,405
		$	461,941	$	579,612	$	1,041,553

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, 2013, 2012 and 2011:

		For the Year Ended December 31, 2013
			Canada			United States		Total
			(in $ thousands)
Revenue
	Sales(1)	$	676,502		$	675,970	$	1,352,472
Deduct(2)
	Production costs(3)		293,339			160,400		453,739
	Depletion, depreciation, amortization and accretion		300,464			292,739		593,203
	Current and deferred income tax provision (recovery)		(21,787	)		60,429		38,642
Results of operations for oil and gas producing activities		$	104,486		$	162,402	$	266,888

		For the Year Ended December 31, 2012
			Canada		United States			Total
			(in $ thousands)
Revenue
	Sales(1)	$	707,985	$	445,349		$	1,153,334
Deduct(2)
	Production costs(3)		301,676		100,548			402,224
	Depletion, depreciation, amortization, accretion and impairment		322,121		1,019,271			1,341,392
	Current and deferred income tax provision (recovery)		15,646		(288,637	)		(272,991	)
Results of operations for oil and gas producing activities		$	68,542	$	(385,833	)	$	(317,291	)

E-4      ENERPLUS 2013 ANNUAL INFORMATION FORM

		For the Year Ended December 31, 2011
			Canada		United States			Total
			(in $ thousands)
Revenue
	Sales(1)	$	824,213	$	334,376		$	1,158,589
Deduct(2)
	Production costs(3)		276,975		64,189			341,164
	Depletion, depreciation, amortization, accretion and impairment		287,754		431,262			719,016
	Current and deferred income tax provision (recovery)		258		(82,671	)		(82,413	)
Results of operations for oil and gas producing activities		$	259,226	$	(78,404	)	$	180,822

Notes:

(1)

Sales are presented net of royalties

(2)

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

(3)

Production costs include operating costs, transportation costs and production taxes.

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

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, 2013
		Canada		United States		Total
		(in $ millions)
Future cash inflows	$	5,078	$	5,133	$	10,212
Future production costs		2,297		1,614		3,911
Future development and asset retirement costs		495		606		1,100
Future income tax expenses		197		642		840
Future net cash flows	$	2,088	$	2,271	$	4,360
Deduction: 10% annual discount factor		892		949		1,840
Standardized measure of discounted future net cash flows	$	1,197	$	1,323	$	2,519

	As at December 31, 2012
		Canada		United States		Total
		(in $ millions)
Future cash inflows	$	5,196	$	3,774	$	8,970
Future production costs		2,233		846		3,079
Future development and asset retirement costs		510		683		1,193
Future income tax expenses		187		423		610
Future net cash flows	$	2,267	$	1,822	$	4,090
Deduction: 10% annual discount factor		991		768		1,760
Standardized measure of discounted future net cash flows	$	1,276	$	1,054	$	2,330

ENERPLUS 2013 ANNUAL INFORMATION FORM      E-5

	As at December 31, 2011
		Canada		United States		Total
		(in $ millions)
Future cash inflows	$	7,210	$	3,141	$	10,351
Future production costs		2,712		639		3,351
Future development and asset retirement costs		546		461		1,007
Future income tax expenses		525		685		1,210
Future net cash flows	$	3,427	$	1,357	$	4,784
Deduction: 10% annual discount factor		1,473		600		2,073
Standardized measure of discounted future net cash flows	$	1,954	$	757	$	2,711

F. CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND NATURAL GAS RESERVES

			2013			2012			2011
			(in $ millions)
Beginning of year		$	2,330		$	2,711		$	2,259
	Sales of oil and natural gas produced, net of production costs		(898	)		(754	)		(814	)
	Net changes in sales prices and production costs		217			(1,050	)		669
	Changes in previously estimated development costs incurred during the period		677			842			830
	Changes in estimated future development costs		(572	)		(967	)		(1,016	)
	Extension, discoveries and improved recovery, net of related costs		515			514			963
	Purchase of reserves in place		140			88			2
	Sales of reserves in place		(163	)		(149	)		(27	)
	Net change resulting from revisions in previous quantity estimates		159			480			(192	)
	Accretion of discount		218			283			215
	Net change in income taxes		(142	)		350			(165	)
	Other significant factors (Exchange rate)		38			(18	)		(14	)
End of year		$	2,519		$	2,330		$	2,711

E-6      ENERPLUS 2013 ANNUAL INFORMATION FORM

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: 403.298.2211
www.enerplus.com

QuickLinks

Exhibit 99.1

Summary of Oil and Gas Reserves (Forecast Prices and Costs) As of December 31, 2013
Summary of Net Present Value of Future Net Revenue Attributable to Oil and Gas Reserves (Forecast Prices and Costs) As of December 31, 2013