ENERPLUS Corp (Form: 40-F, Received: 02/19/2021 06:20:42)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F


☐	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
	OR
☒	ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

7
	For the fiscal year ended December 31, 2020	Commission File Number 001-15150

ENERPLUS CORPORATION

(Exact name of Registrant as specified in its charter)

Alberta, Canada

(Province or other jurisdiction of incorporation or organization)
1311

(Primary Standard Industrial Classification Code Number (if applicable))
N/A

(I.R.S. Employer Identification Number (if applicable))
The Dome Tower, 3000, 333 - 7^th Avenue S.W.
Calgary, Alberta, Canada T2P 2Z1
(403) 298-2200

(Address and telephone number of Registrant’s principal executive offices)
CT Corporation System
28 Liberty Street
New York, New York 10005
(212) 894-8940

(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Shares	ERF	The New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this Form:


☒ Annual information form	☒ Audited annual financial statements
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
222,547,600 Common Shares
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
Yes ☒ No ☐
Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).
Yes ☒ No ☐
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.
Emerging growth company ☐
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.
☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012. Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ This annual report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statements under the Securities Act of 1933 on Form F-10 (File No. 333-231548) and Form S-8 (File Nos. 333-200583 and 333-171836).

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 40-F contains or incorporates by reference forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “plan”, “intend”, “guidance”, “objective”, “strategy”, “should”, “believe” and similar expressions. These statements represent management’s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of the Registrant. Undue reliance should not be placed on these forward-looking statements which are based upon management’s assumptions and are subject to known and unknown risks and uncertainties which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. For a description of some of these risks, uncertainties, events and circumstances, readers should review the disclosure under the heading “Risk Factors” in the Registrant’s Annual Information Form for the year ended December 31, 2020, which is attached as Exhibit 99.1 to this Annual Report on Form 40-F, and under the heading “Risk Factors and Risk Management” in the Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2020, which is attached as Exhibit 99.3 to this Annual Report on Form 40-F, and is incorporated by reference herein. Other than as required by applicable law, the Registrant undertakes no obligation to update publicly or revise any forward-looking statements contained herein and such statements are expressly qualified by the cautionary statement.

ANNUAL INFORMATION FORM, AUDITED ANNUAL CONSOLIDATED
FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS

A.	Annual Information Form

The Registrant’s Annual Information Form for the year ended December 31, 2020 is attached as Exhibit 99.1 to this Annual Report on Form 40-F and is incorporated by reference herein.

B.	Audited Annual Consolidated Financial Statements

The Registrant’s audited annual consolidated financial statements for the year ended December 31, 2020, including the report of the independent registered public accounting firm with respect thereto, are attached as Exhibit 99.2 to this Annual Report on Form 40-F and are incorporated by reference herein.

C.	Management’s Discussion and Analysis

The Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2020 is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated by reference herein.

D.	Supplemental Information About Oil and Gas Producing Activities

The Registrant’s Supplemental Information About Oil and Gas Producing Activities for the year ended December 31, 2020 is attached as Exhibit 99.12 to this Annual Report on Form 40-F and is incorporated by reference herein.

DISCLOSURE REGARDING CONTROLS AND PROCEDURES

A.	Disclosure Controls and Procedures

As of the end of the Registrant’s fiscal year ended December 31, 2020, an evaluation of the effectiveness of the Registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the Registrant’s principal executive officer and principal financial officer. Based upon that evaluation, the Registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the Registrant’s disclosure controls and procedures (which include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrant in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Registrant’s management, including its principal executive and principal financial officers, or

persons performing similar functions, as appropriate to allow for timely decisions regarding required disclosure) are effective to ensure that the information required to be disclosed by the Registrant in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

B.	Management’s Annual Report on Internal Control Over Financial Reporting

The Registrant’s report of management on the Registrant’s internal control over financial reporting is included under the heading “Management’s Report on Internal Control Over Financial Reporting” contained in Exhibit 99.2 to this Annual Report on Form 40-F, which report of management is incorporated by reference herein.

C.	Attestation Report of the Independent Registered Public Accounting Firm

The attestation report of the independent registered public accounting firm on the effectiveness of internal control over financial reporting is included under the heading “Report of Independent Registered Public Accounting Firm” contained in Exhibit 99.2 to this Annual Report on Form 40-F, which attestation report is incorporated by reference herein.

D.	Changes in Internal Control over Financing Reporting

During the fiscal year ended December 31, 2020, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

None.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that Mr. Robert B. Hodgins, a member and the chairman of the Registrant’s Audit & Risk Management Committee, and Mr. Jeffrey W. Sheets, a member of the Registrant’s Audit & Risk Management Committee, are “audit committee financial experts” (as such term is defined by the rules and regulations of the Securities and Exchange Commission) and are “independent” (as that term is defined by the New York Stock Exchange’s listing standards applicable to the Registrant).

The Securities and Exchange Commission has indicated that the designation or identification of a person as an “audit committee financial expert” does not (i) mean that such person is an “expert” for any purpose, including without limitation for purposes of Section 11 of the Securities Act of 1933, (ii) impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the audit committee and the board of directors in the absence of such designation or identification, or (iii) affect the duties, obligations or liability of any other member of the audit committee or the board of directors.

CODE OF ETHICS

The Registrant has adopted a “code of ethics” (as that term is defined by the rules and regulations of the Securities and Exchange Commission), entitled the “Code of Business Conduct” (as amended to the date of this Annual Report on Form 40-F, the “Code of Business Conduct”), that applies to each director, officer (including its principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions), employee and consultant of the Registrant. The Registrant has amended the Code of Business Conduct effective January 12, 2021. There were no amendments made to the Code of Business Conduct of a substantive nature. During the fiscal year ended December 31, 2020, there were no waivers, including implicit waivers, granted from any provision of the Code of Business Conduct that applied to the Registrant’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.

The Code of Business Conduct is attached as Exhibit 99.11 to this Annual Report on Form 40-F.

PRINCIPAL ACCOUNTANT FEES AND SERVICES AND
PRE-APPROVAL POLICIES AND PROCEDURES

The aggregate fees owed by the Corporation to KPMG, an Independent Registered Public Accounting Firm, and the independent auditor of Enerplus, for professional services rendered in Enerplus' last two fiscal years are as follows:


	2020	2019

	(in Cdn$ thousands)
Audit fees⁽¹⁾	894.4	778.8
Audit-related fees⁽²⁾	—	—
Tax fees⁽²⁾	32.0	145.7
All other fees⁽³⁾	—	—
Total	926.4	924.5

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

(2)	Tax fees were for tax compliance, tax advice and tax planning and review to identify recovery opportunities.

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

The Registrant’s Audit & Risk Management Committee has implemented a policy restricting the services that may be provided by the Registrant’s auditors and the fees paid to the Registrant’s auditors. Prior to the engagement of the Registrant’s auditors to perform both audit and non-audit services, the Audit & Risk Management Committee pre-approves the provision of the services. In making their determination regarding non-audit services, the Audit & Risk Management Committee considers the compliance with the policy and the provision of non-audit services in the context of avoiding an adverse impact on auditor independence. All audit and non-audit fees paid to KPMG LLP were pre-approved by the Registrant’s Audit & Risk Management Committee and none were approved on the basis of the de minimis exemption set forth in Rule 2-01(c)(7)(i)(C) of Regulation S-X. Based on the Audit & Risk Management Committee’s discussions with management and the independent auditors, the committee is of the view that the provision of the non-audit services by KPMG LLP described above is compatible with maintaining that firm’s independence from the Registrant.

OFF-BALANCE SHEET ARRANGEMENTS

The Registrant has no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on the Registrant’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

The Registrant has the following contractual obligations, which are set forth in the table below:


	Payments due by period (in Cdn$ thousands)
Contractual Obligations	Total		2021		2022 to 2023		2024 to 2025		2026 +
Senior unsecured notes⁽¹⁾	$	490,422	$	103,836	$	230,578	$	129,286	$	26,722
Transportation commitments		289,993		44,539		59,751		58,189		127,514
Processing commitments		9,489		1,519		3,038		3,038		1,894
Operating lease obligations		39,991		14,643		15,248		7,404		2,695
Total⁽²⁾⁽³⁾	$	829,895		164,537		308,615		197,917		158,825

Notes:

(1)	Interest payments have not been included.

(2)	Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(3)	U.S. dollar commitments have been converted to Canadian dollars using the December 31, 2020 foreign exchange rate of US$1.00 = Cdn$1.2725.

Additional disclosure regarding the Registrant’s contractual obligations is provided under the heading “Liquidity and Capital Resources — Commitments” in the Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2020 attached as Exhibit 99.3 to this Annual Report on Form 40-F, which disclosure is incorporated by reference herein, and in Note 16 to the Registrant’s audited annual consolidated financial statements for the year ended December 31, 2020 attached as Exhibit 99.2 to this Annual Report on Form 40-F, which note is incorporated by reference herein.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Registrant has a separately-designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The members of the Registrant’s Audit & Risk Management Committee are Robert B. Hodgins (Committee Chair), Judith D. Buie, Karen E. Clarke-Whistler, and Jeffrey W. Sheets. Hilary A. Foulkes, the Chair of the board of directors of the Registrant, is an ex officio member of the Audit & Risk Management Committee.

COMPLIANCE WITH NYSE CORPORATE GOVERNANCE RULES

The Registrant has reviewed the New York Stock Exchange’s corporate governance rules and confirms that the Registrant’s corporate governance practices are not significantly nor materially different than those required of domestic companies under the New York Stock Exchange’s listing standards.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.	Undertaking

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

B.	Consent to Service of Process

1.	The Registrant previously filed with the Commission a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

2.	Any change to the name or address of the Registrant’s agent for service shall be communicated promptly to the Commission by amendment to Form F-X referencing the file number of the Registrant.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

	ENERPLUS CORPORATION

	By:	/s/ Ian C. Dundas
		Ian C. Dundas
		President and Chief Executive Officer

Date: February 19, 2021

EXHIBIT INDEX


99.1		Annual Information Form for the year ended December 31, 2020 dated February 19, 2021.
99.2		Audited annual consolidated financial statements for the year ended December 31, 2020.
99.3		Management’s Discussion and Analysis for the year ended December 31, 2020.
99.4		Consent of Independent Registered Public Accounting Firm.
99.5		Consent of McDaniel & Associates Consultants Ltd.
99.6		Consent of Netherland, Sewell & Associates, Inc.
99.7		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.8		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.9		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.10		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.11		Code of Business Conduct.
99.12		Supplemental Information About Oil and Gas Producing Activities.
101		Interactive Data File.

Exhibit 99.1

ANNUAL INFORMATION FORM

For the year ended December 31, 2020

February 19, 2021

‌


TABLE OF CONTENTS	Page


GLOSSARY OF TERMS	1
ABBREVIATIONS AND CONVERSIONS	3
PRESENTATION OF OIL AND GAS RESERVES, CONTINGENT RESOURCES, AND PRODUCTION INFORMATION	5
Note To Reader Regarding Oil And Gas Information, Definitions And National Instrument 51-101	5
Disclosure Of Reserves And Production Information	5
Barrels Of Oil And Cubic Feet Of Gas Equivalent	6
Interests In Reserves, Contingent Resources, Production, Wells And Properties	6
Reserves Categories And Levels Of Certainty For Reported Reserves	6
Development And Production Status	7
Description Of Price And Cost Assumptions	7
PRESENTATION OF FINANCIAL INFORMATION	7
FORWARD-LOOKING STATEMENTS AND INFORMATION	7
CORPORATE STRUCTURE	11
Enerplus Corporation	11
Material Subsidiaries	11
Organizational Structure	11
GENERAL DEVELOPMENT OF THE BUSINESS	12
Developments In The Past Three Years	12
BUSINESS OF THE CORPORATION	13
Overview	13
Summary Of Principal Production Locations	13
Capital Expenditures And Costs Incurred	14
Exploration And Development Activities	15
Oil And Natural Gas Wells And Unproved Properties	15
Description Of Properties	16
Quarterly Production History	18
Quarterly Netback History	19
Tax Horizon	20
Marketing Arrangements And Forward Contracts	21
OIL AND NATURAL GAS RESERVES	22
Summary Of Reserves	22
Forecast Prices And Costs	24
Undiscounted Future Net Revenue By Reserves Category	25
Net Present Value Of Future Net Revenue By Reserves Category And Product Type	26
Estimated Production For Gross Reserves Estimates	27
Future Development Costs	28
Reconciliation Of Reserves	28
Undeveloped Reserves	30
Significant Factors Or Uncertainties	31
Proved And Probable Reserves Not On Production	32
SUPPLEMENTAL OPERATIONAL INFORMATION	32
Environmental, Social And Governance	32
Insurance	34
Personnel	35
DESCRIPTION OF CAPITAL STRUCTURE	35
Common Shares	35
Preferred Shares	35
Senior Unsecured Notes	35
Bank Credit Facility	36
DIVIDENDS	36
Dividend Policy And History	36
Stock Dividend Program	36
INDUSTRY CONDITIONS	38
Overview	38

Pricing And Marketing Of Crude Oil And Natural Gas	38
Royalties And Incentives	39
Land Tenure	39
Environmental Regulation	40
Worker Safety	44
RISK FACTORS	44
MARKET FOR SECURITIES	62
DIRECTORS AND OFFICERS	63
Directors Of The Corporation	63
Officers Of The Corporation	64
Common Share Ownership	64
Conflicts Of Interest	65
Audit & Risk Management Committee Disclosure	65
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	65
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	65
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS	65
INTERESTS OF EXPERTS	66
TRANSFER AGENT AND REGISTRAR	66
ADDITIONAL INFORMATION	66
APPENDIX A – CONTINGENT RESOURCES INFORMATION	A-1
APPENDIX B – REPORT ON RESERVES DATA AND CONTINGENT RESOURCES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	B-1
APPENDIX C – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	C-1
APPENDIX D – AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE PURSUANT TO NATIONAL INSTRUMENT 52-110	D-1

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, Contingent Resources, and Production Information" in this Annual Information Form and under “Note to Reader Regarding Disclosure of Contingent Resources Information” in Appendix A. All references to “Annual Information Form” include this Annual Information Form of the Corporation dated February 19, 2021 for the year ended December 31, 2020 and all appendices hereto.

"ABCA" means the Business Corporations Act (Alberta), as amended

"AECO" means the Canadian benchmark trading price for natural gas

"Bank Credit Facility" means, as at December 31, 2020, the Corporation's US$600 million unsecured, covenant-based revolving credit facility with a syndicate of financial institutions. See “Description of Capital Structure – Bank Credit Facility and Term Facility” and "Material Contracts and Documents Affecting the Rights of Securityholders"

"Board" means the board of directors of the Corporation

"Bruin" means Bruin E&P HoldCo, LLC, a Delaware limited liability company

"Bruin Acquisition" means the proposed acquisition by Enerplus USA of all of the equity interests of Bruin pursuant to the Purchase Agreement. See "General Development of the Business – Developments in the Past Three Years"

"Bruin Material Change Report" means the material change report dated January 29, 2021 in connection with the Bruin

Acquisition and available under the Corporation's SEDAR profile at www.sedar.com and on the Corporation's EDGAR

profile under Form 6-K at www.sec.gov

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

"Commitment Letter" means a binding commitment letter dated January 25, 2021 pursuant to which two Canadian chartered banks have committed, subject to the terms and conditions set forth therein, to make the Term Facility available to the Corporation

"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, 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 requires, 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 (Revised) – Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities, issued by the Canadian securities regulatory authorities

"Enerplus" means the Corporation and, where the context requires, 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

"EOR" mean enhanced oil recovery, as described in more detail under “Business of the Corporation – Description of Properties”

"Equity Financing" means the $132 million bought deal offering (reflecting the exercise of the over-allotment option by

the underwriters for the offering) of the Common Shares, which was completed on February 3, 2021

ENERPLUS 2020 ANNUAL INFORMATION FORM 1

"ESG" means environmental, social and governance

"ESG Policy" means the Corporation's Environmental, Social and Governance Policy

"Financial Statements" means the audited consolidated financial statements of the Corporation as at December 31, 2020 and 2019 and for the three years ended December 2020, 2019 and 2018

"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

"GHG" means greenhouse gas

"GLJ" means GLJ Petroleum Consultants, independent petroleum consultants

"H&S Policy" means the Corporation's Health & Safety Policy

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

"McDaniel" means McDaniel & Associates Consultants Ltd., independent petroleum consultants

"McDaniel Reports" means, collectively, the independent engineering evaluations of certain of the Corporation's oil, natural gas liquids and natural gas reserves in Canada and certain of the Corporation's oil, natural gas liquids and natural gas reserves in the United States, prepared by McDaniel effective December 31, 2020 utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2021

"MD&A" means management's discussion and analysis for the year ended December 31, 2020

“NAFTA” means North American Free Trade Agreement

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

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

"NSAI Report" means the independent engineering evaluation of the Corporation's shale gas reserves and contingent resources in the Marcellus properties prepared by NSAI effective December 31, 2020, utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2021

“NYMEX” means the New York Mercantile Exchange, a U.S.-based commodities futures market

"NYSE" means the New York Stock Exchange

"Purchase Agreement" means the membership interest purchase and sale agreement dated as of January 25, 2021

among the Vendor, as seller, Bruin, and Enerplus USA, as purchaser

"Purchase Price" means US$465 million

“Scope 1 Emissions” means all direct GHG emissions

“Scope 2 Emissions” means indirect GHG emissions from consumption of purchased electricity, heat, or steam

“Scope 3 Emissions” means other indirect emissions not covered in Scope 2 that occur in the value chain, including both upstream and downstream emissions

"SEC" means the United States Securities and Exchange Commission

"Senior Unsecured Notes" means, as at December 31, 2020, the US$385.4 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"

"Sproule" means Sproule Associates Limited, independent petroleum consultants

2 ENERPLUS 2020 ANNUAL INFORMATION FORM

"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

"TCFD" means the Task Force on Climate-related Financial Disclosures

"Term Facility" means a US$400 million senior unsecured term credit facility with two Canadian chartered banks maturing three years from the closing date of the Bruin Acquisition. See "Description of Capital Structure – Bank Credit Facility and Term Facility"

"TSX" means the Toronto Stock Exchange

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

"USMCA" means United States-Mexico-Canada Agreement

"Vendor" means Bruin Purchaser LLC

"WTI" means West Texas Intermediate crude oil that serves as the benchmark crude oil for NYMEX crude oil contracts delivered at Cushing, Oklahoma

Abbreviations and Conversions

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


API		American Petroleum Institute gravity, a measure of how heavy or light a petroleum liquid is compared to water
bbls		barrels, with each barrel representing 34.972 imperial gallons or 42 U.S. gallons
bbls/day		barrels per day
Bcf		one billion cubic feet
BcfGE⁽¹⁾		one billion cubic feet of natural gas equivalent
BOE⁽¹⁾		barrels of oil equivalent
BOE/day⁽¹⁾		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
Mcfe		one thousand cubic feet equivalent
Mcfe/d		one thousand cubic feet equivalent per day
MMBOE⁽¹⁾		one million barrels of oil equivalent
MMbtu		one million British Thermal Units
MMcf		one million cubic feet
Mt		one million tonnes
NGLs		natural gas liquids
NPV		net present value of future net revenue, discounted at 10%

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 BcfGEs. For further information, see "Presentation of Oil and Gas Reserves, Contingent 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, 2020, the exchange rate for one U.S. dollar, expressed in Canadian dollars and based upon the closing rate from Bloomberg, which was CDN$1.2725.

ENERPLUS 2020 ANNUAL INFORMATION FORM 3

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

4 ENERPLUS 2020 ANNUAL INFORMATION FORM

Presentation of Oil and Gas Reserves, Contingent 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 and, unless otherwise expressly stated, does not give effect to the Bruin Acquisition. Readers should also refer to the Report on Reserves Data and Contingent Resources Data by McDaniel and 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 Contingent Resources and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2020 and the preparation dates for such information are January 29, 2021 for the McDaniel Reports and February 4, 2021 for the NSAI Report.

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.

For information regarding contingent resources of the Corporation and its presentation, see Appendix A.

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.

In this Annual Information Form, all oil and natural gas information includes tight oil and shale gas, respectively, unless expressly indicated that it is being presented on a separate basis. 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 necessarily represent the fair market value of such reserves. See "Oil and Natural Gas Reserves – Summary of Reserves" for additional information.

Unless expressly stated otherwise, no oil or gas reserves, production or other operational information presented in this Annual Information Form gives effect to the Bruin Acquisition or any of Bruin's assets, production, reserves or other operational information. For additional information regarding the Bruin Acquisition and Bruin's assets, production, reserves or other operational information, see the Bruin Material Change Report.

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 and specifically in accordance with NI 51-101, which are not comparable in all respects to United States disclosure standards under Subpart 1200 of Regulation S-K 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 and estimation of proved reserves and probable reserves may differ from the definitions and estimation 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 applicable royalties 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, plus royalty interests. Moreover, in accordance with Canadian disclosure requirements, the Corporation has determined and disclosed estimated future net revenue from its reserves using forecast prices and escalating costs, whereas the SEC generally requires that reserves 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 Corporation's fiscal year-end, with the option of also disclosing reserves estimates based upon future or other prices and constant costs. As a consequence of the foregoing, the Corporation's reserves estimates and production volumes may not be comparable to those made by

ENERPLUS 2020 ANNUAL INFORMATION FORM 5

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 securities regulatory authorities allow disclosure of oil and gas resources. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "Note to Reader Regarding Disclosure of Contingent Resources Information" in Appendix A.

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 BcfGEs. The conventions BOEs, MBOEs, MMBOEs, and BcfGEs may be misleading, particularly if used in isolation because 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.

INTERESTS IN RESERVES, CONTINGENT RESOURCES, 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, reserves or contingent resources, 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

(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, reserves or contingent resources, 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

(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.

6 ENERPLUS 2020 ANNUAL INFORMATION FORM

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

DESCRIPTION OF PRICE AND COST ASSUMPTIONS

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

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

(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

The Corporation presents its financial information in accordance with U.S. GAAP. The Corporation continues to qualify as a foreign private issuer for the purposes of its U.S. securities filings based on the most recent assessment performed as at June 30, 2020. The Corporation is required to reassess this conclusion annually, at the end of the second quarter. See "Risk Factors – The Corporation could lose its status as a "foreign private issuer" in the United States, which may result in additional compliance costs and restricted access to capital markets".

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 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

ENERPLUS 2020 ANNUAL INFORMATION FORM 7

prove to be correct, and such forward-looking information included in this Annual Information Form should not be relied upon unduly. 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:

●

completion, size, expenses and timing of the closing of the Bruin Acquisition

●

anticipated benefits of the Bruin Acquisition

●

impact of the Bruin Acquisition on the Corporation's operations, reserves, inventory and opportunities, financial

condition and overall strategy

●

the Term Facility

●

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

●

crude oil, NGLs and natural gas production levels

●

commodity prices, foreign currency exchange rates and interest rates

●

operating expenditures

●

current capital expenditure programs, drilling programs, development plans and other future expenditures, including the planned allocation of capital expenditures among the Corporation's properties 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 divestments, 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

●

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

●

treatment of, and compliance by the Corporation with, governmental and other regulatory regimes and tax, environmental and other laws

●

the Corporation’s ESG initiatives, including specific targets relating to GHG emissions and freshwater use reductions

●

estimates of the Corporation’s future abandonment and reclamation obligations

●

future dividends that may be paid by the Corporation

●

future repurchases of Common Shares by the Corporation

The forward-looking information contained in this Annual Information Form reflects several material factors and expectations and assumptions made by the Corporation including, without limitation: the satisfaction of the conditions to closing the Bruin Acquisition, including in a timely manner; the satisfaction of the conditions to draw down under the Term Facility; there will be some stability, or no further deterioration, in the global economic and market environment, including from the COVID-19 pandemic; the Corporation's current commodity price and other cost assumptions will generally be accurate; the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures, repurchase shares, and other requirements as needed; the Corporation's conduct and results of operations

8 ENERPLUS 2020 ANNUAL INFORMATION FORM

will be consistent with its expectations; the Corporation and its industry partners will have the ability to develop the Corporation's crude oil and natural gas properties in the manner currently contemplated; a lack of infrastructure does not result in the Corporation or a third party curtailing its production and/or receiving reductions to its realized prices; 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; and there will be sufficient availability of services and labour to conduct the Corporation's operations as planned.

The Corporation’s current 2021 capital expenditure budget of $335 million to $385 million contained in this Annual Information Form assumes: the completion of the Bruin Acquisition on the timeframe currently contemplated, a WTI price of US$55/bbl, a Bakken crude oil price differential of US$3.25/bbl below WTI, a NYMEX natural gas price of US$3.00/Mcf and a foreign exchange rate of USD/CDN 1.27.

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 this 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:

●	the Bruin Acquisition may not be completed in accordance with its terms or at all

●	failure to realize anticipated benefits of the Bruin Acquisition

●	ongoing volatility in market prices for crude oil, NGLs and natural gas, including changes in supply or demand for those products, and the Corporation’s realized prices

●

actions by governmental or regulatory authorities, including as a result of ongoing global pandemic or mandated production curtailments or 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

●	changes in general economic, market (including credit market) and business conditions in North America and

worldwide

●	changes in political environment and public opinion

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

●	changes in foreign currency exchange rates, including Canadian currency compared to U.S., and its impact on the Corporation’s operations and financial condition

●	changes in interest rates

●	changes in development plans by the Corporation or third-party operators

●	the ability of the Corporation to comply with debt covenants under the Credit Facilities

●	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 services, third party processing capacity and skilled personnel

●	incorrect assessments of the value of acquisitions or divestments, or the failure to complete divestments

ENERPLUS 2020 ANNUAL INFORMATION FORM 9

●	constraints on, or the unavailability of, adequate infrastructure, including pipeline and other transportation capacity, to deliver the Corporation's production to market, whether in the control of the Corporation or not

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

●

changes in tax, environmental, regulatory, or other legislation applicable to the Corporation and its operations, including as a result of climate change initiatives, and the Corporation's ability to comply with current and future environmental legislation and regulations and other laws and regulations, including those impacting financial institutions, that could limit commodity market liquidity

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, which are available on the internet under the Corporation's SEDAR profile at www.sedar.com, 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.

10 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 the 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. 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 in connection with the implementation of a stock dividend program. See "Description of Capital Structure – Common Shares" and "Dividends – 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 Suite 2200, 950 - 17th Street, 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, 2020, 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, 2020 is set forth below.

ENERPLUS 2020 ANNUAL INFORMATION FORM 11

General Development of the Business

DEVELOPMENTS IN THE PAST THREE YEARS

Since 2018, the Corporation has focused on maintaining a strong balance sheet and returning cash to shareholders through its continued monthly dividend and share repurchases through its normal course issuer bids on the TSX and NYSE. From the beginning of 2018 through March 2020, the Corporation repurchased an aggregate of approximately 24.4 million Common Shares for $260.3 million. The Corporation did not renew its normal course issuer bid in March 2020 in order to preserve capital and maintain balance sheet strength.

In 2020, the onset of the COVID-19 pandemic resulted in a sudden global economic downturn creating significant challenges for the energy industry and reduced global demand for oil and natural gas. In response to the decline in crude oil demand and historically low prices, Enerplus suspended its operated drilling and completions activity and temporarily began curtailed production from certain wells across its crude oil and natural gas liquids properties during the second quarter to preserve cash flow. As commodity prices improved, Enerplus brought the majority of the curtailed production back online by early July, reinstated its guidance and resumed limited completion activity during the fourth quarter under a lower capital spending program.

On January 25, 2021, Enerplus announced that Enerplus USA had entered into the Purchase Agreement and agreed to acquire Bruin for the Purchase Price, which is payable in cash and subject to certain adjustments. Closing of the Bruin Acquisition is subject to customary closing conditions, and closing is expected to occur in early March 2021. Concurrent with the announcement of the Bruin Acquisition, Enerplus entered into the Commitment Letter providing for the new US$400 million Term Facility (See "Description of Capital Structure – Bank Credit Facility and Term Facility"). Additionally, Enerplus announced the Equity Financing, which closed February 3, 2021. The Corporation issued 33.1 million common shares at a price of $4.00 per share for gross proceeds of $132.3 million ($126.2 million, net of issuance costs).

The net proceeds of the Equity Financing, together with the proceeds from the Term Facility, are intended to be used to finance the Purchase Price, and to fund capital expenditures on the acquired properties and other expenses in connection with the Bruin Acquisition. If, however, the Bruin Acquisition is not completed, the net proceeds from the Equity Financing will be used to partially fund capital expenditures, as well as the repayment of near-term maturities on the Senior Unsecured Notes and for other general corporate purposes.

For additional information on the Bruin Acquisition, see the Bruin Material Change Report.

12 ENERPLUS 2020 ANNUAL INFORMATION FORM

Business of the Corporation

OVERVIEW

The Corporation's crude oil and natural gas property interests are located in the United States, primarily in North Dakota, Montana, Colorado and Pennsylvania, as well as in western Canada in the provinces of Alberta, British Columbia and Saskatchewan. Capital spending on these assets in 2020 totaled $291.4 million with 81% of spending focused on the Corporation’s crude oil assets in the United States.

Capital spending on the Corporation’s Williston Basin and Colorado assets totaled $234.8 million during 2020. Capital spending on the Corporation’s natural gas interests in northeast Pennsylvania was $33.1 million. Canadian crude oil waterflood properties had capital spending of $23.0 million during 2020 and $0.5 million was spent on Canadian natural gas properties.

In 2020, the Corporation spent $17.7 million on abandonment and reclamation activities, $10.1 million of which related to the abandonment of its Tommy Lakes asset in British Columbia with the remaining $7.6 million spent across various other Canadian properties. In addition, the Corporation completed a total of $10.1 million on minor acquisitions of leases and undeveloped land and recorded net divestments of $6.1 million.

Production volumes for the year ended December 31, 2020 from the Corporation's properties consisted of 56% crude oil and NGLs and 44% natural gas, on a BOE basis. The Corporation's major producing properties generally have related field facilities and infrastructure to accommodate its production. The Corporation's 2020 average daily production was 90,697 BOE/day, comprised of: 38,243 bbls/day of tight oil, 3,901 bbls/day of heavy oil, 3,277 bbls/day of light and medium oil (a total of 45,421 bbls/day of crude oil), 5,633 bbls/day of NGLs and 237,857 Mcf/day of natural gas (includes 225,543 Mcf/day of shale gas). Production decreased approximately 10% compared to 2019 average daily production of 101,042 BOE/day, comprised of: 41,079 bbls/day of tight oil, 4,717 bbls/day of heavy oil, 3,908 bbls/day of light and medium oil (totalling 49,704 bbls/day of crude oil), 4,929 bbls/day of NGLs and 278,451 Mcf/day of natural gas (includes 255,051 Mcf/day of shale gas). See "Summary of Principal Production Locations". The decrease in average daily production in 2020 compared to 2019 is largely attributable to Enerplus’ response to the COVID-19 global pandemic which resulted in crude oil demand destruction along with an oversupplied crude oil market, causing a swift and significant collapse in global crude oil commodity prices. In response, Enerplus scaled back its capital program and temporarily curtailed crude oil production to preserve cash flow and the sustainability of the business. The Corporation’s 2020 production in the United States was 89% of its total production, with the remaining 11% from Canada. Approximately 53% of the Corporation’s 2020 production was operated by the Corporation, with the remainder operated by industry partners.

At December 31, 2020, the crude oil and natural gas property interests held by the Corporation were estimated to contain total proved plus probable gross reserves of 9.0 MMbbls of light and medium crude oil, 22.3 MMbbls of heavy crude oil, 170.1 MMbbls of tight oil, 23.5 MMbbls of NGLs, 23.2 Bcf of conventional natural gas and 1,173.9 Bcf of shale gas, for a total of 424.4 MMBOE. The Corporation's proved reserves represented approximately 71% of total proved plus probable reserves, with approximately 53% of the Corporation's proved plus probable reserves weighted to crude oil and NGLs. See "Oil and Natural Gas Reserves".

Unless otherwise noted: (i) all production, reserves and operational information in this Annual Information Form is presented as at or, where applicable, for the year ended, December 31, 2020 and does not give effect to the Bruin Acquisition, (ii) all production information represents the Corporation's company interest 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 reserves volumes represent gross reserves using forecast prices and costs. See "Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information".

SUMMARY OF PRINCIPAL PRODUCTION LOCATIONS

For the year ended December 31, 2020, on a BOE basis, 89% of the Corporation's production was derived from the United States (49% from North Dakota, 35% from Pennsylvania, 3% from Montana, and 2% from Colorado) and 11% from Canada (8% from Alberta and 3% from Saskatchewan). The following table describes the average daily production from the Corporation's principal producing properties and regions during the year ended December 31, 2020.

ENERPLUS 2020 ANNUAL INFORMATION FORM 13

2020 Average Daily Production from Principal Properties and Regions


	Products
	Crude Oil
					Conventional
	Light and				Natural	Shale
Property/Region	Medium	Heavy	Tight	NGLs	Gas	Gas	Total
	(bbls/day)	(bbls/day)	(bbls/day)	(bbls/day)	(Mcf/day)	(Mcf/day)	(BOE/day)
United States
Fort Berthold, North Dakota	-	-	35,123	4,917	-	27,491	44,622
Marcellus, Pennsylvania	-	-	-	-	-	193,002	32,167
Sleeping Giant, Montana	-	-	1,884	1	-	3,709	2,503
DJ Basin, Colorado	-	-	1,233	86	-	1,147	1,511
Other U.S.	-	-	3	-	-	28	8
Total United States	-	-	38,243	5,005	-	225,376	80,811

Canada
Freda Lake, Saskatchewan	2,346	-	-	-	-	-	2,346
Medicine Hat Glauconitic "C" Unit, Alberta	-	2,017	-	-	234	-	2,056
Giltedge, Alberta	-	1,317	-	-	118	-	1,337
Ante Creek, Alberta	842	-	-	35	1,236	-	1,084
Ferrier, Alberta	52	-	-	116	2,808	-	635
Cadogan, Alberta	-	532	-	7	88	-	554
Pine Creek, Alberta	1	-	-	109	2,263	-	487
Willesden Green North, Alberta	1	-	-	138	1,936	-	462
Other Canada	35	35	-	223	3,631	167	925
Total Canada	3,277	3,901	-	628	12,314	167	9,886

Total	3,277	3,901	38,243	5,633	12,314	225,543	90,697

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

CAPITAL EXPENDITURES AND COSTS INCURRED

The Corporation invested $291.4 million in its capital program during 2020, with 88% directed to crude oil-related projects, approximately 53% lower than 2019 capital spending. Capital investment during 2020 was focused primarily in the Corporation’s U.S. North Dakota Bakken crude oil property (with investment of $212.6 million), Sleeping Giant capital spending of $0.3 million and its Denver-Julesburg (“DJ Basin”) assets in Colorado where it invested $21.9 million. The Corporation’s U.S. Marcellus non-operated assets received capital investment of $33.1 million during the year. Capital spending on Canadian assets included $23.0 million on crude oil waterflood properties and $0.5 million on Canadian natural gas properties.

In the financial year ended December 31, 2020, 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)
United States	$	-	$	7.5	$	0.6	$	267.4
Canada		0.3		2.3		0.1		23.3
Total	$	0.3	$	9.8	$	0.7	$	290.7

Based on a budgeted commodity price of US$55 per barrel WTI for crude oil and US$3.00 per Mcf NYMEX for natural gas, and assuming the closing of the Bruin Acquisition in early March 2021 as expected, the Corporation’s 2021 exploration and development capital spending plans are estimated to be between $335 million to $385 million.

The Corporation intends to finance its 2021 capital expenditure program with cash, internally generated cash flow, proceeds from the Equity Financing and/or debt. The Corporation will review its 2021 capital investment plans throughout the year in the context of prevailing economic conditions, commodity prices and potential acquisitions and divestments, making adjustments as it deems necessary. See "Forward-Looking Statements and Information".

14 ENERPLUS 2020 ANNUAL INFORMATION FORM

For further information regarding the Corporation's properties and its 2020 exploration and development activities, 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, 2020, in each of Canada and the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.


	United States				Canada
	Development Wells		Exploratory Wells		Development Wells		Exploratory Wells
Category of Well	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Crude oil wells	50	27	-	-	6	5	-	-
Natural gas wells	70	5	-	-	-	-	-	-
Service wells	-	-	-	-	5	5	-	-
Dry and abandoned wells	1	1	-	-	-	-	-	-
Total	121	33	-	-	11	10	-	-

For a description of the Corporation’s 2021 development plans and the anticipated sources of funding these plans, see "Capital Expenditures and Costs Incurred", above.

OIL AND NATURAL GAS WELLS AND UNPROVED PROPERTIES

The following table summarizes, at December 31, 2020, the Corporation's interests in producing wells and wells which were drilled but not producing, but which may be capable of production in the future (the “Non-Producing Wells”), 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
United States
Colorado	12	11	-	-	18	3	-	-	30,725	26,952
Montana	254	174	-	-	12	8	-	-	-	-
North Dakota	332	256	-	-	30	23	-	-	783	783
Pennsylvania	-	-	958	99	-	-	78	10	22,380	6,456
Canada
Alberta	469	229	178	53	276	144	144	50	57,512	22,966
British Columbia	-	-	5	1	-	-	109	102	20,101	16,078
Saskatchewan	59	56	81	23	22	20	11	4	14,644	8,870
Total	1,126	726	1,222	176	358	198	342	166	146,145	82,105

The Corporation expects its rights to explore, develop and exploit on approximately 3,644 and 204 net acres of unproved properties in Canada and the United States, respectively, to expire, in the ordinary course, prior to December 31, 2021. The Corporation has no material work commitments on its unproved 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.

For any properties with no reserves or on unproved lands, the Corporation does not have any significant abandonment and reclamation costs, unusually high expected development costs or operating costs, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations. Operating expenditures and abandonment and reclamation costs for all properties with no reserves or on unproved lands are included in the Corporation’s MD&A and asset retirement disclosures in the Financial Statements.

ENERPLUS 2020 ANNUAL INFORMATION FORM 15

DESCRIPTION OF PROPERTIES

Outlined below is a description of the Corporation's U.S. and Canadian crude oil and natural gas properties and assets, all of which are located onshore.

For additional information on contingent resources associated with certain of the Corporation’s United States and Canadian crude oil and natural gas properties, including estimated volumes of economic contingent resources, see "Appendix A – Contingent Resources Information".

U.S. Crude Oil Properties

OVERVIEW

The Corporation’s primary U.S. crude oil properties are located in the Fort Berthold region of North Dakota, the Wattenberg Field in Weld County of the DJ Basin of Colorado and in Richland County, Montana. The Corporation spent $234.8 million on its U.S. crude oil assets in 2020.

The Corporation has approximately 66,440 net acres of land in Fort Berthold, primarily in Dunn and McKenzie Counties and, on a production basis, operates approximately 88% of its Fort Berthold asset. The Corporation’s Fort Berthold property produces a light sweet crude oil (42° API), with some associated natural gas and NGLs, from both the Bakken and Three Forks formations. Fort Berthold production averaged 44,622 BOE/day in 2020 consisting of 35,123 bbls/day of tight oil, 4,917 bbls/day of NGLs and 27,491 Mcf/day of natural gas. During 2020, the Corporation spent $212.6 million on its operated and non-operated assets in North Dakota. This included drilling 21.8 net horizontal wells (18.8 operated and 3.0 non-operated) in the Fort Berthold region, targeting both the Bakken and Three Forks formations (all of which were long lateral wells), with 23.9 net wells brought on-stream (20 operated and 3.9 non-operated). At the end of 2020, the Corporation had 22.2 net operated drilled uncompleted wells in North Dakota.

The Corporation holds approximately 38,190 net acres (held through leasing and farm-ins) in the DJ Basin of Colorado (northwest Weld County, Wattenberg Field). The Wattenberg Field has been producing since the 1970’s and is characterized as having high recoveries and initial production rates, long reserves life and multiple stacked producing horizons. Capital investment in the DJ Basin in 2020 was $21.9 million and focused on the drilling of 5.3 net wells (4.4 operated and 0.9 non-operated) and bringing 1.8 net operated wells onstream. Average annual production for 2020 was 1,511 BOE/day (82% tight oil). At the end of 2020, the Corporation had 2.6 net operated drilled uncompleted wells in Colorado.

The Corporation also has working interests in Sleeping Giant, a mature, light oil property located in the Elm Coulee Field in Richland County, Montana. Sleeping Giant produced 2,503 BOE/day on average from the Bakken formation in 2020, consisting of 1,884 bbls/day of tight oil and 3,709 Mcf/day of natural gas.

Overall, the Corporation's U.S. crude oil properties produced an average of 48,636 BOE/day in 2020, down 2% from 2019 primarily due to temporary production curtailments and the suspension of its operated North Dakota drilling and completions program early in 2020 due to weak commodity prices. On a BOE basis, production from U.S. crude oil properties represented 54% of the Corporation's 2020 average daily production of 90,697 BOE/day.

Approximately 11.3 MMBOE of proved plus probable reserves were added at Fort Berthold during 2020, including technical revisions and economic factors. After adjusting for 2020 production of 16.3 MMBOE, total proved plus probable reserves associated with this property as at December 31, 2020 were 203.7 MMBOE, approximately 2.4% less than at December 31, 2019.

The Corporation had 216.2 MMBOE of proved plus probable reserves associated with its U.S. crude oil assets at December 31, 2020, representing approximately 51% of its total proved plus probable reserves.

The Corporation has entered into long-term agreements for the gathering, dehydration, processing, compression and transportation of the Corporation's share of crude oil, natural gas and NGL production from its North Dakota and Montana properties. These agreements are intended to provide the Corporation with cost certainty, and access to the U.S. Gulf Coast, where it can further access export crude oil markets. See “Marketing Arrangements and Forward Contracts” for further information. The Corporation has also entered into a long-term agreement for gas processing in the DJ Basin under a contract with dedicated lands, but no take or pay, or minimum commitments.

16 ENERPLUS 2020 ANNUAL INFORMATION FORM

U.S. Natural Gas Properties

OVERVIEW

The Corporation's U.S. natural gas properties consist entirely of its non-operated Marcellus shale gas interests located in northeastern Pennsylvania, where the Corporation holds an interest in approximately 32,630 net acres. The Corporation's Marcellus shale gas production averaged 193 MMcf/day in 2020, representing approximately 35% of the Corporation's total average daily production of 90,697 BOE/day.

In 2020, $33.1 million was invested in the Corporation's non-operated Marcellus interests. The Corporation participated in the drilling of 4.8 net wells and 2.2 net wells were brought on-stream. At the end of 2020, the Corporation had 4.3 net non-operated drilled uncompleted wells.

Proved plus probable Marcellus shale gas reserves were 1,031.2 Bcf as at December 31, 2020, a decrease of 8.4 Bcf from 2019, and represented 40% of the Corporation's total proved plus probable reserves.

The Corporation has entered into long-term agreements for the gathering, dehydration, 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 access to the northeastern United States and broader U.S. natural gas markets through connections with major interstate pipelines. See “Marketing Arrangements and Forward Contracts” for further information.

Canadian Crude Oil Properties

OVERVIEW

Production from the Corporation’s Canadian crude oil properties comes primarily from mature, low decline assets under waterflood and EOR techniques. Primary waterfloods inject water into the formation using injection wells to supplement 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 more predictable production profile and more stable declines, as well as higher recovery of reserves. Infill drilling, well injection optimization and EOR techniques are effective methods of improving recovery of reserves even further. These properties have associated crude oil production facilities for emulsion treatment and injection or water disposal.

The Canadian crude oil waterfloods provide a stable production base and cash flow to support the Corporation’s overall capital spending, as well as its dividend. Total Canadian waterflood production averaged 7,469 BOE/day (approximately 50% split between light and medium oil and heavy oil) during 2020, or 8% of the Corporation’s total average daily production of 90,697 BOE/day. Capital investment in the Canadian crude oil waterflood properties was $23.0 million and focused on its Giltedge waterflood asset in Alberta, where it drilled and brought on-stream 10 net injector/producer wells.

At December 31, 2020, there were 32.1 MMBOE, or approximately 8% of the Corporation’s total proved plus probable reserves on a BOE basis associated with Canadian crude oil properties using waterflood or EOR techniques.

Canadian Natural Gas Properties

OVERVIEW

The Corporation's primary Canadian natural gas properties are located in Alberta. During 2020, production from the Corporation's Canadian natural gas properties averaged 14,853 Mcfe/day. The Corporation's largest producing Canadian natural gas property in 2020 was Ferrier, Alberta.

Capital spending on the Corporation’s Canadian natural gas assets during 2020 was approximately $0.5 million. There are no material reserves associated with these properties at December 31, 2020.

ENERPLUS 2020 ANNUAL INFORMATION FORM 17

QUARTERLY PRODUCTION HISTORY

The following table sets forth the Corporation's average daily production volumes, on a company interest basis, by product type, for each fiscal quarter in 2020 and for the entire year, separately for production in Canada and the United States, and in total.


	Year Ended December 31, 2020
	First	Second	Third	Fourth
Country and Product Type	Quarter	Quarter	Quarter	Quarter	Annual
United States
Light and medium oil (bbls/day)	-	-	-	-	-
Heavy oil (bbls/day)	-	-	-	-	-
Tight oil (bbls/day)	41,208	37,102	38,684	35,997	38,243
Total crude oil (bbls/day)	41,208	37,102	38,684	35,997	38,243
Natural gas liquids (bbls/day)	4,636	4,316	5,849	5,210	5,005
Total liquids (bbls/day)	45,844	41,418	44,533	41,207	43,248
Conventional natural gas (Mcf/day)	-	-	-	-	-
Shale gas (Mcf/day)	248,000	223,264	218,699	211,766	225,376
Total United States (BOE/day)	87,177	78,629	80,983	76,501	80,811

Canada
Light and medium oil (bbls/day)	3,480	3,154	3,281	3,192	3,277
Heavy oil (bbls/day)	4,356	2,912	4,117	4,216	3,901
Tight oil (bbls/day)	-	-	-	-	-
Total crude oil (bbls/day)	7,836	6,066	7,398	7,408	7,178
Natural gas liquids (bbls/day)	710	613	608	580	628
Total liquids (bbls/day)	8,546	6,679	8,006	7,988	7,806
Conventional natural gas (Mcf/day)	14,650	12,119	12,131	10,380	12,314
Shale gas (Mcf/day)	263	196	65	146	167
Total Canada (BOE/day)	11,032	8,731	10,039	9,743	9,886

Total
Light and medium oil (bbls/day)	41,208	37,102	38,684	35,997	38,243
Heavy oil (bbls/day)	3,480	3,154	3,281	3,192	3,277
Tight oil (bbls/day)	4,356	2,912	4,117	4,216	3,901
Total crude oil (bbls/day)	49,044	43,168	46,082	43,405	45,421
Natural gas liquids (bbls/day)	5,346	4,929	6,457	5,790	5,633
Total liquids (bbls/day)	54,390	48,097	52,539	49,195	51,054
Conventional natural gas (Mcf/day)	14,650	12,119	12,131	10,380	12,314
Shale gas (Mcf/day)	248,263	223,460	218,764	211,912	225,543
Total (BOE/day)	98,209	87,360	91,022	86,244	90,697

18 ENERPLUS 2020 ANNUAL INFORMATION FORM

QUARTERLY NETBACK HISTORY

The following tables set forth the Corporation's average netbacks received for each fiscal quarter in 2020 and for the entire year, separately for production in Canada and the United States. Netbacks are calculated on the basis of prices received, which are net of transportation costs but before the effects of commodity derivative instruments, less related royalties and production costs. For multiple product wells, 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, 2020
	First		Second		Third		Fourth
Light and Medium Crude Oil ($ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
Canada
Sales price⁽¹⁾	$	45.87	$	19.24	$	42.68	$	43.44	$	38.10
Transportation		(1.45)		(1.66)		(1.84)		(1.62)		(1.64)
Royalties⁽²⁾		(12.49)		(2.30)		(10.67)		(10.57)		(9.12)
Production costs⁽³⁾		(20.13)		(12.06)		(14.09)		(16.04)		(15.68)
Netback	$	11.80	$	3.22	$	16.08	$	15.21	$	11.66


	Year Ended December 31, 2020
	First		Second		Third		Fourth
Heavy Oil ($ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
Canada
Sales price⁽¹⁾	$	33.10	$	19.92	$	40.04	$	40.47	$	34.50
Transportation		(1.87)		(1.74)		(1.72)		(1.95)		(1.83)
Royalties⁽²⁾		(5.18)		(1.22)		(5.20)		(5.06)		(4.42)
Production costs⁽³⁾		(16.74)		(20.40)		(12.08)		(18.70)		(16.72)
Netback	$	9.31	$	(3.44)	$	21.04	$	14.76	$	11.53


	Year Ended December 31, 2020
	First		Second		Third		Fourth
Tight Oil ($ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
United States
Sales price⁽¹⁾	$	53.68	$	32.35	$	47.43	$	49.22	$	45.89
Transportation		(3.62)		(3.98)		(3.46)		(3.54)		(3.65)
Royalties⁽²⁾		(14.91)		(9.54)		(13.12)		(13.62)		(12.85)
Production costs⁽³⁾		(15.72)		(12.07)		(14.07)		(14.71)		(14.18)
Netback	$	19.43	$	6.76	$	16.78	$	17.35	$	15.21


	Year Ended December 31, 2020
	First		Second		Third		Fourth
Natural Gas Liquids ($ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
United States
Sales price⁽¹⁾	$	11.01	$	(3.25)	$	9.69	$	16.14	$	8.90
Transportation		(1.90)		(1.97)		(1.66)		(1.80)		(1.82)
Royalties⁽²⁾		(2.15)		0.68		(1.77)		(3.19)		(1.69)
Production costs⁽³⁾		-		-		-		-		-
Netback	$	6.96	$	(4.54)	$	6.26	$	11.15	$	5.39

Canada
Sales price⁽¹⁾	$	23.90	$	15.17	$	19.37	$	26.68	$	21.32
Transportation		(2.32)		(1.85)		(1.62)		(2.01)		(1.96)
Royalties⁽²⁾		(6.97)		(5.04)		(5.24)		(7.90)		(6.30)
Production costs⁽³⁾		-		-		-		-		-
Netback	$	14.61	$	8.28	$	12.51	$	16.77	$	13.06

ENERPLUS 2020 ANNUAL INFORMATION FORM 19


	Year Ended December 31, 2020
	First		Second		Third		Fourth
Conventional Natural Gas ($ per Mcf)	Quarter		Quarter		Quarter		Quarter		Annual
Canada
Sales price⁽¹⁾	$	2.18	$	2.18	$	2.89	$	3.24	$	2.58
Transportation		(0.55)		(0.57)		(1.04)		(1.10)		(0.79)
Royalties⁽²⁾		0.32		(0.28)		0.08		0.32		0.11
Production costs⁽³⁾		(3.36)		(2.20)		(3.72)		(2.10)		(2.90)
Netback	$	(1.41)	$	(0.87)	$	(1.79)	$	0.36	$	(1.00)

The production associated with the Canadian conventional natural gas netback represents approximately 2% of the Corporation’s total production.


	Year Ended December 31, 2020
	First		Second		Third		Fourth
Shale Gas ($ per Mcf)	Quarter		Quarter		Quarter		Quarter		Annual
United States
Sales price⁽¹⁾	$	2.07	$	1.60	$	1.65	$	1.98	$	1.83
Transportation		(0.84)		(0.89)		(0.82)		(0.81)		(0.84)
Royalties⁽²⁾		(0.44)		(0.36)		(0.43)		(0.47)		(0.42)
Production costs⁽³⁾		(0.11)		(0.11)		(0.10)		(0.12)		(0.11)
Netback	$	0.68	$	0.24	$	0.30	$	0.58	$	0.46

Canada
Sales price⁽¹⁾	$	2.58	$	2.29	$	3.31	$	3.92	$	2.86
Transportation		(0.55)		(0.57)		(1.04)		(1.10)		(0.73)
Royalties⁽²⁾		(0.19)		(0.19)		1.20		(0.24)		(0.06)
Production costs⁽³⁾		(1.65)		(2.23)		(4.96)		(5.00)		(2.88)
Netback	$	0.19	$	(0.70)	$	(1.49)	$	(2.42)	$	(0.81)

The production associated with the Canadian shale gas netback represents a small portion of the Corporation’s total production.

Notes:

(1)	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.

TAX HORIZON

The Corporation is subject to standard applicable corporate income taxes. Based on existing tax legislation, the Corporation’s available tax pools, expected capital expenditures and forecasted net income, the Corporation does not anticipate paying material cash taxes in either Canada or the United States until after 2023. These expectations may vary depending on numerous factors, including fluctuations in commodity prices, the Corporation's capital spending, changes in tax laws, and the nature and timing of the Corporation's acquisitions and divestments. 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 laws or free trade agreements, including those affecting tax, royalties and other financial and trade matters, and interpretations of those laws and trade agreements, may adversely affect the Corporation and its securityholders”.

For additional information, see Notes 2(j) and 13 to the Financial Statements and the information under the heading "Income Taxes" in the Corporation's MD&A, which can be found on its SEDAR profile at www.sedar.com and on the Corporation's EDGAR profile at www.sec.gov.

20 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 in Canada, negotiated contracts ranging from 30 days up to two years for crude oil in the U.S., and yearly contracts for NGLs in Canada, where terms fluctuate with the monthly spot markets. NGLs contracts in the U.S. are linked to processing arrangements with pricing linked to the monthly spot markets. The Corporation received an average price (before transportation costs, royalties, and the effects of commodity derivative instruments) of $44.35/bbl for its crude oil and $10.29/bbl for its NGLs for the year ended December 31, 2020, compared to $68.98/bbl for its crude oil and $15.19/bbl for its NGLs for the year ended December 31, 2019.

In the United States, the Corporation transports its U.S. crude oil production to its buyers by pipeline and/or truck, and may occasionally sell a portion to buyers who may utilize rail transportation (after title is transferred into the buyer’s name). In 2020, the Corporation received an average price differential for its U.S. Bakken crude oil of US$4.96/bbl below WTI, compared to an average of US$3.61/bbl below WTI in 2019. The Corporation has firm transportation of 3,550 barrels per day on the Dakota Access Pipeline ("DAPL") on which it transports a portion of its North Dakota crude oil production to the U.S. Gulf Coast, where it can further access export crude oil markets. The Corporation’s NGLs associated with its U.S. crude oil production volumes are marketed on its behalf by midstream companies in North Dakota, Montana and Colorado. See "Risk Factors – Sales Pipelines and Rail Transportation Systems".

In Canada, the Corporation typically transports its Canadian crude oil production to its buyers by pipeline and/or truck. The Corporation may occasionally sell a portion of its crude oil production to buyers who may use rail transportation (after title is transferred into the buyer’s name). The Corporation has firm transportation capacity for approximately 820 BOE/day on average from 2022 to 2027. Additionally, the Corporation has contracted firm NGLs fractionation agreements for 1,125 bbls/day through 2027.

Natural Gas

In marketing its natural gas production, the Corporation strives for a mix of contracts and customers. In 2020, 81% of the Corporation's natural gas production originated from its non-operated Marcellus interest in northeast Pennsylvania. The Corporation delivered approximately 50% of its Marcellus production in 2020 onto the Transco Leidy Pipeline, with most of the remaining volumes delivered onto the Tennessee Gas Pipeline 300 Line in Pennsylvania. A portion was then transported to the Kentucky/Tennessee border. The Corporation has firm sales contracts for up to 65 MMcf/day of natural gas production in the Marcellus for terms of up to eight years with buyers who hold pipeline capacity on these and other pipelines in the region. The Corporation also has firm transportation agreements to transport gas within and out of the region for approximately 68 MMcf/day, with terms ending between 2022 and 2036.

The average price received by the Corporation (before transportation, royalties, and the effects of commodity derivative instruments) for its natural gas in 2020 was $1.87/Mcf compared to $2.87/Mcf for the year ended December 31, 2019. In 2020, the Corporation received an average price differential for its U.S. Marcellus shale gas production of US$0.65/Mcf below NYMEX compared to an average of US$0.39/Mcf below NYMEX in 2019. Approximately 14% of the Corporation's natural gas production was associated natural gas production from its crude oil operations in North Dakota, Montana and the DJ Basin. The Corporation does not market these volumes directly, as they are marketed on Enerplus’ behalf by midstream companies.

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 monthly sales portfolio reflects a mix of the daily and monthly market indices. Approximately 5% of the Corporation's total natural gas production originated in Canada in 2020. At December 31, 2020, the Corporation held firm service natural gas transportation contracts for its natural gas production in Canada for 2021 totalling 31 MMcf/day.

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 Notes 15(b) and 15(c)(i) to the Financial Statements and under the heading "Results of Operations – Price Risk Management" in the Corporation's MD&A, 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.

ENERPLUS 2020 ANNUAL INFORMATION FORM 21

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 98% of the net present value (discounted at 10%, before tax, using forecast prices and costs) of the Corporation's total proved plus probable reserves.

McDaniel, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 86% of the net present value (discounted at 10%, before tax, 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, Montana and Colorado. McDaniel used the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2021 to prepare its report. The Corporation has evaluated the remaining 14% of the net present value of its Canadian properties using similar evaluation parameters, including the same forecast price and inflation 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. For consistency in the Corporation's reserves reporting, NSAI used the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2021 to prepare its report.

The Corporation used the average of the forecast exchange rates of GLJ, McDaniel and Sproule, set forth below, to convert U.S. dollar amounts in both the McDaniel and NSAI Reports to Canadian dollar amounts for presentation in this Annual Information Form.

The following sections and tables summarize, as at December 31, 2020, the Corporation's crude oil, NGLs and natural gas reserves and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions associated with such reserves 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, 2019 to December 31, 2020, 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 transportation. The NGLs prices were adjusted to reflect historical average prices received.

It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The reserves 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, Contingent Resources, and Production Information" in conjunction with the following tables and notes.

The reserves information presented in this section does not give effect to the Bruin Acquisition. For information on Bruin's oil, NGLs and natural gas reserves as at December 31, 2020 as independently evaluated by McDaniel, see the Bruin Material Change Report.

22 ENERPLUS 2020 ANNUAL INFORMATION FORM

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, 2020, using forecast price and cost cases.

Summary of Oil and Gas Reserves (Forecast Prices and Costs)

As of December 31, 2020


	OIL AND NATURAL GAS RESERVES
	Light &						Natural Gas		Conventional
RESERVES	Medium Oil		Heavy Oil		Tight Oil		Liquids		Natural Gas		Shale Gas		Total
CATEGORY	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)
Proved Developed Producing
Canada	5,884	4,894	15,052	13,076	-	-	832	785	17,279	17,945	525	499	24,735	21,829
United States	-	-	-	-	51,508	41,481	7,291	5,844	-	-	567,733	456,332	153,421	123,380
Total	5,884	4,894	15,052	13,076	51,508	41,481	8,123	6,629	17,279	17,945	568,258	456,831	178,156	145,209
Proved Developed Non-Producing
Canada	93	77	-	-	-	-	0	0	0	0	-	-	93	77
United States	-	-	-	-	2,970	2,397	326	260	-	-	3,918	3,194	3,949	3,189
Total	93	77	-	-	2,970	2,397	326	260	0	0	3,918	3,194	4,043	3,266
Proved Undeveloped
Canada	660	563	1,893	1,587	-	-	2	1	74	63	-	-	2,567	2,161
United States	-	-	-	-	51,708	41,403	6,449	5,158	-	-	357,370	283,680	117,719	93,841
Total	660	563	1,893	1,587	51,708	41,403	6,451	5,159	74	63	357,370	283,680	120,286	96,002
Total Proved
Canada	6,637	5,534	16,946	14,663	-	-	833	787	17,353	18,008	525	499	27,396	24,068
United States	-	-	-	-	106,186	85,281	14,066	11,262	-	-	929,021	743,206	275,089	220,410
Total	6,637	5,534	16,946	14,663	106,186	85,281	14,900	12,048	17,353	18,008	929,546	743,705	302,485	244,478
Probable
Canada	2,383	1,906	5,309	4,542	-	-	295	283	5,811	5,928	148	141	8,980	7,742
United States	-	-	-	-	63,941	51,224	8,306	6,646	-	-	244,240	195,640	112,954	90,477
Total	2,383	1,906	5,309	4,542	63,941	51,224	8,602	6,929	5,811	5,928	244,388	195,781	121,934	98,219
Total Proved Plus Probable
Canada	9,020	7,440	22,254	19,204	-	-	1,129	1,069	23,164	23,936	673	640	36,376	31,809
United States	-	-	-	-	170,127	136,505	22,372	17,908	-	-	1,173,261	938,846	388,043	310,887
Total	9,020	7,440	22,254	19,204	170,127	136,505	23,501	18,977	23,164	23,936	1,173,934	939,485	424,419	342,697

ENERPLUS 2020 ANNUAL INFORMATION FORM 23

Summary of Net Present Value of Future Net Revenue

Attributable to Oil and Gas Reserves (Forecast Prices and Costs)

As of December 31, 2020


	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)
	Before Deducting Income Taxes					After Deducting Income Taxes⁽¹⁾					Unit
RESERVES CATEGORY	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%	Value⁽²⁾

	(in $ millions)										$/BOE
Proved Developed Producing
Canada	150	211	198	175	154	150	211	198	175	154		$9.05
United States	1,705	1,386	1,155	994	878	1,667	1,370	1,148	991	877		$9.36
Total	1,855	1,597	1,353	1,169	1,032	1,817	1,581	1,346	1,166	1,030		$9.32

Proved Developed Non‑Producing
Canada	2	1	1	1	1	2	1	1	1	1		$13.30
United States	53	46	38	32	27	53	46	38	32	27		$11.96
Total	55	47	39	33	28	55	47	39	33	28		$11.99

Proved Undeveloped
Canada	38	23	13	6	1	38	23	13	6	1		$5.82
United States	1,080	677	436	285	183	852	547	357	234	150		$4.65
Total	1,118	700	449	290	185	889	569	370	240	151		$4.68

Total Proved
Canada	190	235	211	181	156	190	235	211	181	156		$8.77
United States	2,839	2,109	1,630	1,311	1,089	2,571	1,963	1,544	1,257	1,054		$7.39
Total	3,028	2,344	1,841	1,492	1,244	2,761	2,198	1,755	1,438	1,209		$7.53

Probable
Canada	197	115	74	52	39	197	115	74	52	39		$9.61
United States	1,794	1,056	681	474	351	1,314	777	503	354	266		$7.52
Total	1,990	1,171	755	526	389	1,511	892	577	406	304		$7.69

Total Proved Plus Probable
Canada	386	350	286	233	194	386	350	286	233	194		$8.98
United States	4,633	3,165	2,310	1,785	1,439	3,885	2,740	2,046	1,611	1,319		$7.43
Total	5,019	3,515	2,596	2,018	1,633	4,271	3,090	2,332	1,844	1,513		$7.57

Notes:

(1) Income tax calculations are based on the forecast cash flows of reserves volumes only, taking into consideration the forecast capital required to develop the reserves, the estimated abandonment, decommissioning and reclamation costs of the Corporation, and having regard for remaining corporate tax pools at the effective date, applicable deductions and appropriate federal, provincial and state tax rates.

(2) 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.

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 is based on the following average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021 (utilized by McDaniel, 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:


								NATURAL GAS LIQUIDS
	CRUDE OIL					NATURAL GAS		Edmonton Par Price
										Condensate
			Western		Sask	Alberta	U.S. Henry			&
		Edmonton	Canadian	Alberta	Cromer	AECO	Hub			Natural	Inflation	Exchange
Year	WTI⁽¹⁾	Light⁽²⁾	Select⁽³⁾	Heavy⁽⁴⁾	Medium⁽⁵⁾	Spot Prices	Gas Price	Propane	Butanes	Gasolines	Rate	Rate
	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/MMbtu)	($US/MMbtu)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	(%/year)	($US/$Cdn)
2021	47.17	55.76	44.63	39.87	53.77	2.78	2.83	18.18	26.36	59.24	0.0	0.768
2022	50.17	59.89	48.18	43.20	57.31	2.70	2.87	21.91	32.85	63.19	1.3	0.765
2023	53.17	63.48	52.10	46.86	60.68	2.61	2.90	24.57	39.20	67.34	2.0	0.763
2024	54.97	65.76	54.10	48.67	62.90	2.65	2.96	25.47	40.65	69.77	2.0	0.763
2025	56.07	67.13	55.19	49.65	64.22	2.70	3.02	26.00	41.50	71.18	2.0	0.763
2026	57.19	68.53	56.29	50.65	65.57	2.76	3.08	26.54	42.36	72.61	2.0	0.763
2027	58.34	69.95	57.42	51.67	66.94	2.81	3.14	27.09	43.24	74.07	2.0	0.763
2028	59.50	71.40	58.57	52.71	68.35	2.87	3.20	27.65	44.14	75.56	2.0	0.763
2029	60.69	72.88	59.74	53.76	69.78	2.92	3.26	28.23	45.06	77.08	2.0	0.763
2030	61.91	74.34	60.93	54.84	71.19	2.98	3.33	28.79	45.96	78.62	2.0	0.763
2031	63.15	75.83	62.15	55.94	72.61	3.04	3.39	29.37	46.88	80.20	2.0	0.763
2032	64.41	77.34	63.40	57.05	74.06	3.10	3.46	29.95	47.82	81.80	2.0	0.763
2033	65.70	78.89	64.66	58.20	75.55	3.16	3.53	30.55	48.77	83.44	2.0	0.763
2034	67.01	80.47	65.96	59.36	77.06	3.23	3.60	31.16	49.75	85.10	2.0	0.763
2035	68.35	82.08	67.28	60.55	78.60	3.29	3.67	31.79	50.74	86.81	2.0	0.763
Thereafter	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	⁽⁶⁾	2.0	0.763

24 ENERPLUS 2020 ANNUAL INFORMATION FORM

Notes:

(1) West Texas Intermediate at Cushing Oklahoma 40^o API/0.5% sulphur

(2) Edmonton Light Sweet 40^o API/0.3% sulphur

(3)Western Canadian Select at Hardisty, Alberta

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

(5) Midale Cromer Crude Oil 29^o API/2.0% sulphur

(6) Escalation is approximately 2% per year thereafter

In 2020, the Corporation received a weighted average price (before transportation costs, royalties, and the effects of commodity derivative instruments) of $44.35/bbl for crude oil, $10.29/bbl for natural gas liquids and $1.87/Mcf for natural gas.

UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2020, using forecast prices and costs, is set forth below (columns or rows may not add due to rounding):


						Future Net		Future Net
					Abandonment	Revenue		Revenue
					and	Before		After
			Operating	Development	Reclamation	Income	Income	Income
RESERVES CATEGORY	Revenue	Royalties⁽¹⁾	Costs	Costs	Costs	Taxes	Taxes	Taxes⁽²⁾
	(in $ millions)
Proved Reserves
Canada	1,381	203	602	83	303	190	—	190
United States	9,422	2,443	2,748	1,114	278	2,839	268	2,571
Total	10,803	2,646	3,350	1,197	581	3,028	268	2,761
Proved Plus Probable
Reserves
Canada	1,902	287	819	103	306	386	—	386
United States	14,964	3,928	4,281	1,780	343	4,633	747	3,885
Total	16,866	4,215	5,100	1,883	650	5,019	747	4,271

Notes:

(1)	Royalties include any net profits interests paid, as well as the Saskatchewan Corporation Capital Tax Surcharge.

(2)

Income tax calculations are based on the forecast cash flows of reserves volumes only, taking into consideration the forecast capital required to develop the reserves, the estimated abandonment, decommissioning and reclamation costs of the Corporation, and having regard for remaining corporate tax pools at the effective date, applicable deductions and appropriate federal, provincial and state tax rates.

ENERPLUS 2020 ANNUAL INFORMATION FORM 25

NET PRESENT VALUE OF FUTURE NET REVENUE BY RESERVES CATEGORY AND PRODUCT TYPE

The net present value of future net revenue before income taxes by reserves category and product type as of December 31, 2020, using forecast prices and costs and discounted at 10% per year, is set forth below:


		Future Net
		Revenue
		Before Income
		Taxes
RESERVES CATEGORY	PRODUCT TYPE	(Discounted at 10%)	Unit Value⁽¹⁾
		(in $ thousands)	($/bbl; $/Mcf)
Canada
Proved Reserves	Light and Medium Oil (including solution gas and by-products)⁽²⁾	60,803	11.01
	Heavy Oil (including solution gas and by-products) ⁽²⁾	154,958	10.57
	Tight Oil⁽²⁾	n/a	n/a
	Conventional Natural Gas (including by-products)⁽³⁾	(5,633)	(0.41)
	Shale Gas⁽³⁾	1,030	2.06
	Total	211,158
Proved Plus Probable Reserves	Light and Medium Oil (including solution gas and by-products)⁽²⁾	92,514	12.46
	Heavy Oil (including solution gas and by-products) ⁽²⁾	193,908	10.10
	Tight Oil⁽²⁾	n/a	n/a
	Conventional Natural Gas (including by-products)⁽³⁾	(2,190)	(0.12)
	Shale Gas⁽³⁾	1,346	2.10
	Total	285,578
United States
Proved Reserves	Light and Medium Oil (including solution gas and by-products) ⁽²⁾	n/a	n/a
	Heavy Oil (including solution gas and by-products) ⁽²⁾	n/a	n/a
	Tight Oil⁽²⁾	1,059,861	12.43
	Conventional Natural Gas (including by-products) ⁽³⁾	n/a	n/a
	Shale Gas⁽⁴⁾	569,903	0.85
	Total	1,629,764
Proved Plus Probable Reserves	Light and Medium Oil (including solution gas and by-products) ⁽²⁾	n/a	n/a
	Heavy Oil (including solution gas and by-products) ⁽²⁾	n/a	n/a
	Tight Oil⁽²⁾	1,678,020	12.29
	Conventional Natural Gas (including by-products) ⁽³⁾	n/a	n/a
	Shale Gas⁽⁴⁾	632,312	0.77
	Total	2,310,332
Total
Proved Reserves	Light and Medium Oil (including solution gas and by-products) ⁽²⁾	60,803
	Heavy Oil (including solution gas and by-products) ⁽²⁾	154,958
	Tight Oil⁽²⁾	1,059,861
	Conventional Natural Gas (including by-products) ⁽³⁾	(5,633)
	Shale Gas⁽³⁾⁽⁴⁾	570,933
	Total	1,840,922
Proved Plus Probable Reserves	Light and Medium Oil (including solution gas and by-products) ⁽²⁾	92,514
	Heavy Oil (including solution gas and by-products) ⁽²⁾	193,908
	Tight Oil⁽²⁾	1,678,020
	Conventional Natural Gas (including by-products) ⁽³⁾	(2,190)
	Shale Gas⁽³⁾⁽⁴⁾	633,658
	Total	2,595,910

Notes:

(1)	Unit values are calculated using the 10% discounted rate divided by the major product type net reserves for each group.

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

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

(4)	No by-product oil or NGLs are associated with U.S. shale gas.

26 ENERPLUS 2020 ANNUAL INFORMATION FORM

ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

The volume of total production for the Corporation estimated for 2021 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual 2021 production (including from the Fort Berthold and Marcellus properties in the separate tables 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

Estimated 2021

Aggregate

Average Daily

Aggregate

Average Daily

Product Type

Production

Crude Oil

Light and Medium Crude Oil

1,081

Mbbls

2,962

bbls/day

Mbbls

bbls/day

Heavy Oil

1,513

Mbbls

4,144

bbls/day

Mbbls

bbls/day

Tight Oil

Mbbls

bbls/day

13,086

Mbbls

35,852

bbls/day

Total Crude Oil

2,594

Mbbls

7,106

bbls/day

13,086

Mbbls

35,852

bbls/day

Natural Gas Liquids

135

Mbbls

370

bbls/day

1,651

Mbbls

4,523

bbls/day

Total Liquids

2,729

Mbbls

7,476

bbls/day

14,737

Mbbls

40,376

bbls/day

Conventional Natural Gas

2,710

MMcf

7,424

Mcf/day

MMcf

Mcf/day

Shale Gas

MMcf

211

Mcf/day

82,863

MMcf

227,023

Mcf/day

Total

3,193

MBOE

8,748

BOE/day

28,548

MBOE

78,213

BOE/day

Gross Probable Reserves

Canada

United States

Estimated 2021

Aggregate

Average Daily

Aggregate

Average Daily

Product Type

Production

Crude Oil

Light and Medium Crude Oil

Mbbls

108

bbls/day

Mbbls

bbls/day

Heavy Oil

Mbbls

111

bbls/day

Mbbls

bbls/day

Tight Oil

Mbbls

bbls/day

1,126

Mbbls

3,085

bbls/day

Total Crude Oil

Mbbls

219

bbls/day

1,126

Mbbls

3,085

bbls/day

Natural Gas Liquids

Mbbls

bbls/day

146

Mbbls

400

bbls/day

Total Liquids

Mbbls

238

bbls/day

1,272

Mbbls

3,485

bbls/day

Conventional Natural Gas

114

MMcf

313

Mcf/day

MMcf

Mcf/day

Shale Gas

MMcf

Mcf/day

2,335

MMcf

6,397

Mcf/day

Total

106

MBOE

291

BOE/day

1,661

MBOE

4,551

BOE/day

The tables below set forth McDaniel's and NSAI’s estimated 2021 production for the Corporation's Fort Berthold property located in North Dakota, United States, and the Marcellus property, located in Pennsylvania, United States, respectively, as each field is estimated to account for more than 20% of the above estimate of the Corporation's 2021 production.

Gross Proved Reserves

Fort Berthold

Marcellus

Estimated 2021

Aggregate

Average Daily

Aggregate

Average Daily

Product Type

Production

Crude Oil

Light and Medium Crude Oil

Mbbls

bbls/day

Mbbls

bbls/day

Heavy Oil

Mbbls

bbls/day

Mbbls

bbls/day

Tight Oil

11,944

Mbbls

32,723

bbls/day

Mbbls

bbls/day

Total Crude Oil

11,944

Mbbls

32,723

bbls/day

Mbbls

bbls/day

Natural Gas Liquids

1,607

Mbbls

4,403

bbls/day

Mbbls

bbls/day

Total Liquids

13,551

Mbbls

37,126

bbls/day

Mbbls

bbls/day

Conventional Natural Gas

MMcf

Mcf/day

MMcf

Mcf/day

Shale Gas

8,995

MMcf

24,645

Mcf/day

71,986

MMcf

197,222

Mcf/day

Total

15,050

MBOE

41,234

BOE/day

11,998

MBOE

32,870

BOE/day

ENERPLUS 2020 ANNUAL INFORMATION FORM 27

Gross Probable Reserves

Fort Berthold

Marcellus

Estimated 2021

Aggregate

Average Daily

Aggregate

Average Daily

Product Type

Production

Crude Oil

Light and Medium Crude Oil

Mbbls

bbls/day

Mbbls

bbls/day

Heavy Oil

Mbbls

bbls/day

Mbbls

bbls/day

Tight Oil

1,071

Mbbls

2,934

bbls/day

Mbbls

bbls/day

Total Crude Oil

1,071

Mbbls

2,934

bbls/day

Mbbls

bbls/day

Natural Gas Liquids

140

Mbbls

383

bbls/day

Mbbls

bbls/day

Total Liquids

1,211

Mbbls

3,317

bbls/day

Mbbls

bbls/day

Conventional Natural Gas

MMcf

Mcf/day

MMcf

Mcf/day

Shale Gas

785

MMcf

2,150

Mcf/day

1,474

MMcf

4,039

Mcf/day

Total

1,341

MBOE

3,675

BOE/day

246

MBOE

673

BOE/day

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 cash, internally generated cash flow and/or debt. 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".


	CANADA				UNITED STATES
			Proved Plus				Proved Plus
	Proved Reserves		Probable Reserves		Proved Reserves		Probable Reserves
		Discounted		Discounted		Discounted		Discounted
Year	Undiscounted	at 10%/year	Undiscounted	at 10%/year	Undiscounted	at 10%/year	Undiscounted	at 10%/year

	(in $ millions)
2021	9	9	10	9	249	238	250	239
2022	37	32	38	33	277	240	277	240
2023	15	12	20	16	306	242	324	256
2024	6	5	12	9	258	186	366	261
2025	10	7	10	7	24	16	293	191
2026	3	2	8	5	-	-	269	161
Remainder	3	1	5	3	-	-	1	-
Total	83	68	103	82	1,114	921	1,780	1,349

RECONCILIATION OF RESERVES

Overview

The Corporation's total gross proved plus probable reserves at December 31, 2020 were 424.4 MMBOE, a decrease of 4% from year-end 2019. The Corporation's gross proved plus probable crude oil and NGLs reserves were 224.9 MMBOE and represented 53% of total proved plus probable gross reserves, down 7% from year-end 2019. The Corporation replaced approximately 50% of its 2020 gross production through its exploration and development program, adding 16.7 MMBOE of proved plus probable reserves, including revisions and economic factors. Of the Corporation’s 16.7 MMBOE of proved plus probable additions, including revisions and economic factors, 11.3 MMBOE is attributed to the Fort Berthold property and 10.4 MMBOE (62.3 Bcf) to the Marcellus shale gas property, which were partially offset by a decrease of 3.3 MMBOE in the Corporation’s Canadian properties and a decrease of 0.7 MMBOE in the Sleeping Giant property in Montana.

No working interests in reserves volumes were sold in 2020.

28 ENERPLUS 2020 ANNUAL INFORMATION FORM

The following tables reconcile the Corporation's gross crude oil and natural gas reserves from December 31, 2019 to December 31, 2020, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

CANADIAN OIL AND GAS RESERVES


	Light & Medium Oil			Heavy Oil			Tight Oil			Natural Gas Liquids
			Proved			Proved			Proved			Proved
CANADA			Plus			Plus			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
December 31, 2019	7,770	2,788	10,558	20,121	6,470	26,591	-	-	-	1,217	364	1,580
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	-	-	-	—	—	—
Economic Factors	(465)	11	(454)	(1,082)	(506)	(1,589)	-	-	-	(148)	(21)	(168)
Technical Revisions	529	(416)	113	(666)	(655)	(1,320)	-	-	-	(51)	(48)	(98)
Production	(1,197)	-	(1,197)	(1,428)	-	(1,428)	-	-	-	(185)	-	(185)
December 31, 2020	6,637	2,383	9,020	16,946	5,309	22,254	-	-	-	833	295	1,129


	Conventional Natural Gas			Shale Gas			Total
			Proved			Proved			Proved
CANADA			Plus			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)	(MBOE)
December 31, 2019	24,242	7,395	31,637	615	178	793	33,251	10,884	44,135
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	—	—	—
Economic Factors	(2,195)	(588)	(2,783)	(89)	1	(88)	(2,075)	(614)	(2,689)
Technical Revisions	(824)	(997)	(1,821)	61	(31)	30	(314)	(1,290)	(1,604)
Production	(3,870)	-	(3,870)	(61)	-	(61)	(3,466)	-	(3,466)
December 31, 2020	17,353	5,811	23,164	525	148	673	27,396	8,980	36,376

UNITED STATES OIL AND GAS RESERVES


	Light & Medium Oil			Heavy Oil			Tight Oil			Natural Gas Liquids
			Proved			Proved			Proved			Proved
UNITED STATES			Plus			Plus			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
December 31, 2019	-	-	-	-	-	-	112,812	68,240	181,052	13,110	8,032	21,142
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	12,111	6,454	18,565	1,636	698	2,335
Economic Factors	-	-	-	-	-	-	(5,668)	(1,537)	(7,205)	(701)	(188)	(889)
Technical Revisions	-	-	-	-	-	-	890	(9,216)	(8,326)	1,852	(236)	1,616
Production	-	-	-	-	-	-	(13,959)	-	(13,959)	(1,831)	-	(1,831)
December 31, 2020	-	-	-	-	-	-	106,186	63,941	170,127	14,066	8,306	22,372


	Conventional Natural Gas			Shale Gas			Total
			Proved			Proved			Proved
UNITED STATES			Plus			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)	(MBOE)
December 31, 2019	-	-	-	933,122	233,435	1,166,556	281,442	115,178	396,620
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	76,643	38,538	115,181	26,521	13,576	40,097
Economic Factors	-	-	-	(9,881)	(976)	(10,858)	(8,016)	(1,888)	(9,904)
Technical Revisions	-	-	-	11,546	(26,756)	(15,211)	4,667	(13,912)	(9,245)
Production	-	-	-	(82,408)	-	(82,408)	(29,524)	-	(29,524)
December 31, 2020	-	-	-	929,021	244,240	1,173,261	275,089	112,954	388,043

ENERPLUS 2020 ANNUAL INFORMATION FORM 29

TOTAL OIL AND GAS RESERVES


	Light & Medium Oil			Heavy Oil			Tight Oil			Natural Gas Liquids
			Proved			Proved			Proved			Proved
TOTAL			Plus			Plus			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
December 31, 2019	7,770	2,788	10,558	20,121	6,470	26,591	112,812	68,240	181,052	14,327	8,396	22,723
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	—	—	—	-	-	-	12,111	6,454	18,565	1,636	698	2,335
Economic Factors	(465)	11	(454)	(1,082)	(506)	(1,589)	(5,668)	(1,537)	(7,205)	(849)	(209)	(1,058)
Technical Revisions	529	(416)	113	(666)	(655)	(1,320)	890	(9,216)	(8,326)	1,802	(284)	1,518
Production	(1,197)	-	(1,197)	(1,428)	-	(1,428)	(13,959)	-	(13,959)	(2,016)	-	(2,016)
December 31, 2020	6,637	2,383	9,020	16,946	5,309	22,254	106,186	63,941	170,127	14,900	8,602	23,501


	Conventional Natural Gas			Shale Gas			Total

			Proved			Proved			Proved
TOTAL			Plus			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)	(MBOE)
December 31, 2019	24,242	7,395	31,637	933,737	233,613	1,167,349	314,693	126,061	440,755
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	76,643	38,538	115,181	26,521	13,576	40,097
Economic Factors	(2,195)	(588)	(2,783)	(9,970)	(975)	(10,946)	(10,092)	(2,501)	(12,593)
Technical Revisions	(824)	(997)	(1,821)	11,606	(26,788)	(15,181)	4,352	(15,202)	(10,849)
Production	(3,870)	-	(3,870)	(82,470)	-	(82,470)	(32,990)	-	(32,990)
December 31, 2020	17,353	5,811	23,164	929,546	244,388	1,173,934	302,485	121,934	424,419

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
					Conventional
	Light &				Natural	Shale
Year⁽¹⁾	Medium	Heavy	Tight	NGLs	Gas	Gas	Total
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)
2018	450	500	17,345	1,725	-	64,895	30,835
2019	330	-	20,460	2,243	-	81,546	36,624
2020	-	-	9,896	1,397	-	65,091	22,141

Note:

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

Probable Undeveloped Reserves


	Crude Oil
					Conventional
	Light &				Natural	Shale
Year⁽¹⁾	Medium	Heavy	Tight	NGLs	Gas	Gas	Total
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)
2018	205	1,023	12,650	1,258	35	69,512	26,727
2019	150	-	17,026	2,003	-	73,529	31,434
2020	-	-	6,174	687	-	38,195	13,227

Note:

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

30 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 considers each of its undeveloped locations to be projects that have larger capital expenditures and, consistent with the COGE Handbook, has generally assigned development of or the commencement of significant capital spending on proved undeveloped locations to occur within three years (five years for resource plays) and within five years (ten years for resource plays) for probable undeveloped reserves. The Corporation has in recent years continually developed its undeveloped reserves in Canada and the United States. The Corporation intends to fund the development of its undeveloped reserves as of December 31, 2020 with cash, internally generated cash flow and/or debt. These expenditures are expected to extend the continual development of undeveloped reserves in Canada and the United States beyond two years.

In the Fort Berthold property, the Corporation has been active for the last several years in drilling and developing these undeveloped reserves, converting the associated volumes to producing reserves. The Corporation has, in the past, maintained the gross proved plus probable undeveloped location well count year over year and added undeveloped locations to replace those that were drilled in the preceding year. The Corporation expects to increase its activity in Fort Berthold and has increased the operated gross proved plus probable undeveloped location count from 161 locations in 2019 to 174 locations as of December 31, 2020. The conversion of the proved undeveloped locations to producing reserves is scheduled to occur continuously over the next four years and the development of the remaining probable undeveloped locations is scheduled to occur within six years.

In 2020, the Corporation continued to participate in the development of its non-operated undeveloped reserves in the Marcellus property, converting 1.4 net proved plus probable locations to developed reserves. These converted locations were replaced with additions of 4.8 net proved plus probable undeveloped locations as of December 31, 2020. Development timing for both proved undeveloped and proved plus probable undeveloped locations is determined by the scheduling prepared by the operators of the property. In this case, development of the proved undeveloped locations is scheduled to take place over five years and the development of the probable undeveloped locations is scheduled to take place over the next six years.

In Canada, the Corporation’s drilling activity level has been modest in recent years, and in 2020 consisted of drilling 5 gross proved plus probable undeveloped locations at the Giltedge property, which is located in Alberta. In addition to Giltedge, there are also undeveloped reserves assigned in the Cadogan and Medicine Hat ‘Glauc C’ properties, which are located in Alberta, and the Ratcliffe property located in Saskatchewan. Enerplus anticipates there will be drilling activity in the Cadogan, Medicine Hat ‘Glauc C” and Ratcliffe properties starting in 2022. Development of the Canadian proved undeveloped reserves is forecast to occur continuously over the next five years, and the development of the probable undeveloped reserves is forecast to occur over the next six years.

SIGNIFICANT FACTORS OR UNCERTAINTIES

Changes in future commodity 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 adjusted in parallel. 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.

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. There are no significant abandonment and reclamation costs associated with its reserves properties or properties with no attributed reserves, and the Corporation does not anticipate its abandonment and reclamation liabilities to negatively impact its reserves data or its ability to develop these reserves at this time. Abandonment and reclamation costs associated with surface leases, wells, undeveloped locations, facilities and pipelines for all reserves properties in Canada and United States have been reflected in reserves estimates. Additionally, the abandonment and reclamation costs associated with surface leases, wells, facilities and pipelines for Canadian properties to which reserves are no longer attributed have been reflected in reserves estimates to better reflect the value of the Corporation’s Canadian assets.

For further information, see "Risk Factors – The Corporation's actual reserves and resources will vary from its reserves and resources estimates, and those variations could be material" and “– Recent court rulings on the liability surrounding abandonment and reclamation obligations of oil and gas companies may adversely affect the Corporation”.

ENERPLUS 2020 ANNUAL INFORMATION FORM 31

PROVED AND PROBABLE RESERVES NOT ON PRODUCTION

The Corporation has approximately 5.1 MMBOE (0.12 MMBOE in Canada and 4.98 MMBOE in its U.S. oil properties) of proved plus probable reserves which are capable of production but which, as of December 31, 2020, were not on production. These reserves have generally been non-producing for periods ranging from a few months to five years. In Canada, these reserves include one well in the Ante Creek North property and one well in the Ratcliffe. In the United States, the majority of these volumes are associated with operated wells in Colorado (two wells), Montana (27 wells) and North Dakota (15 wells) that are shut-in due to pump failures or in need of a workover. All of these non-producing assets have been scheduled to recommence production in 2021.

Supplemental Operational Information

ENVIRONMENTAL, SOCIAL AND GOVERNANCE

The Corporation has adopted the H&S Policy and the ESG Policy to articulate Enerplus' commitment to health and safety, stakeholder engagement, environmental and regulatory compliance and governance practices. These policies are high-level statements of intent that guide Enerplus' decision-making and are consistent with its values and demonstrate its goal of producing safe and socially responsible energy. The Board and the President & Chief Executive Officer are ultimately accountable for ensuring compliance with both policies. The Corporation's management and its corporate sustainability department are responsible for ensuring they are communicated and integrated across the Corporation. All employees and contractors of the Corporation are responsible for complying with the policies. The Board is responsible for overseeing the Corporation's ESG activities. Furthermore, Enerplus has identified six material ESG focus areas with accountability for each area assigned to a committee of the Board. The Board's Safety and Social Responsibility ("S&SR") Committee has responsibility for four of the six areas, including GHG emissions, water management, health and safety and community engagement, whereas the other two – culture and board constitution and culture – are overseen by the Compensation and Human Resources Committee and the Corporate Governance and Nominating Committee, respectively.

The Corporation strives to develop and operate its oil and natural gas assets in a socially responsible manner and places a high priority on protecting the health and safety of its employees, contractors and the public in the communities in which it operates, as well as preserving the quality of the environment. The Corporation also encourages active and open collaboration with its stakeholders. The Corporation has established processes and programs designed to evaluate and manage health, safety, environmental and regulatory risks, and strives for ongoing improvement in its S&SR and ESG performance.

The H&S Policy discusses the Corporation's commitment to protect the health and safety of all persons and communities involved in, or affected by, its business activities. Specifically, the H&S Policy specifies the Corporation will:

●

Ensure its culture of accountability is applied to personal safety and the safety of others

●

Proactively identify and mitigate life critical safety risks in its operations through a focus on leading indicators and incident investigations

●

Set annual safety targets focused on continuous improvement and monitor performance throughout the year with the Board, leadership, employees and contractors

●

Provide safety training and expect all workers to identify, report and act on all hazards

●

Create and maintain an environment that supports and requires a Stop Work culture

●

Partner with like-minded contractors to incorporate industry best practices into operational standards and processes to keep people safe while delivering operational excellence

The ESG Policy reiterates the Corporation's commitment to environmental, social and governance issues and states that the Corporation will:

●

invest in innovative solutions to reduce greenhouse gas emissions

●

increase the efficiency of energy consumption to reduce emissions intensity

●

improve water and land use practices

●

limit the waste we generate

●

prevent and manage releases

●

monitor environmental performance and provide transparent disclosure

●

continuously improve environmental management system and provide resources and training to improve its capability to meet and exceed environmental commitments

●

proactively comply with all applicable rules and regulations

●

invest in building and sustaining positive relationships with each of its stakeholders

●

continuously monitor culture via multiple qualitative tools and a quantitative survey system

●

engage with community stakeholders to understand their needs and concerns and promote economic and social development in its operating areas

32 ENERPLUS 2020 ANNUAL INFORMATION FORM

●

Support the Board’s engagement and oversight of the development and execution of its ESG approach

The Corporation's commitment to building meaningful and transparent relationships with its stakeholders is embedded in the ESG Policy. In addition, it expresses the Corporation’s commitment to engaging with stakeholders to promote economic and social development for the people and communities in its operating areas. Finally, the Corporation’s commitment to the responsible development of resources and regulatory compliance is published in its ESG Report and Data Tables. The Corporation uses the Global Reporting Initiative Core Standard and the Sustainability Accounting Standards Board materiality map to identify and prioritize ESG issues. In 2019, reporting and disclosure was expanded to include the International Petroleum Industry Environmental Conservation Association guidance for sustainability reporting. These reports discuss and summarize the Corporation’s environmental, safety, social responsibility and governance performance, along with its targets and goals, and can be found at www.enerplus.com.

Health and Safety

The Corporation's total combined (employee/contractor) recordable injury frequency rate for 2020 was 0.16 injuries per 200,000 worker hours, a decrease from the rate of 0.67 recorded in 2019. The Corporation had an employee recordable injury frequency rate of zero per 200,000 worker hours in 2020 compared to 0.49 injuries per 200,000 worker hours in 2019. The Corporation's total contractor recordable injury frequency of 0.24 injuries per 200,000 worker hours in 2020 decreased from 0.71 injuries per 200,000 worker hours in 2019. The Corporation recorded one lost-time injury in 2020, a decrease from five recorded in 2019. The Corporation has not had employee or contractor fatalities for any of the last five years. As an ESG focus area, Enerplus has established a lost time injury frequency reduction target of 25%, on average, from 2020 to 2023, relative to 2019, for its employees and contractors.

Health and safety risks influence workplace practices, operating costs and the establishment of health and safety standards. In addition to integrating targets into its ESG focus areas, the Corporation continues to maintain its health and safety management system, which is designed to:

●	increase emphasis on safety awareness and promote continuous improvement and safety excellence

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

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

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

The Corporation's health and safety management system is reviewed annually for continuous improvement opportunities. 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’s operations are subject to applicable laws and regulations relating to the environment. See "Industry Conditions – Environmental Regulation". The Corporation is committed to meeting its responsibilities to protect the environment through a variety of programs and actively monitors its operations for compliance with all relevant and applicable environmental regulations and industry best practices. Currently, the Corporation engages in the following:

●

Site abandonment and reclamation activities - capital expenditures for the Corporation's Canadian and United States properties in 2020 totaled approximately $17.7 million ($15.0 million on operated properties, including its Tommy Lakes asset, and $2.7 million on non-operated properties). The Corporation received 30 reclamation certificates from regulatory agencies in 2020 by returning sites to their previous equivalent land capability.

●	The Corporation typically undertakes third-party environmental compliance audits designed to ensure compliance with environmental legislation and regulations. However, due to the COVID-19 pandemic, no environmental compliance audits were completed in 2020.

●

Government regulators 77 inspections of the Corporation’s field operations in the United States and Canada in 2020, a decrease compared to the prior year’s 235 government regulator inspections due to the COVID-19 pandemic. As a result, fewer field site inspections of facilities were carried out and, instead, the inspections were focused on administrative compliance (that is, not physical equipment). The percentage of non-compliant inspections received by the Corporation in 2020 increased to 25%, compared to 16% received in 2019

●

The Corporation conducts an internal site inspection program at its U.S. and Canadian locations to proactively assess environmental, regulatory and general housekeeping items. Findings from the internal site inspection program and any action items are recorded in the Corporation’s internal Sustainability Information Management System in order to measure compliance and ensure potential issues are addressed. In addition, the Corporation completed 14 inspections at major Canadian facilities in 2020.

ENERPLUS 2020 ANNUAL INFORMATION FORM 33

●

The Corporation conducts annual property reviews with specific risk reduction objectives. The Corporation also continues to manage risk through its ongoing pipeline risk assessment process and various other activities, such as inspections of pipelines at water crossings. The Corporation reviews each of its pipeline systems annually. The Corporation continues to incorporate improvements to these programs, which are designed to identify and mitigate significant risks, and to decrease the number and severity of pipeline failure incidents.

●

In 2020, the Corporation completed a total of 722 fugitive emissions surveys for its Canadian well sites, facilities and U.S. production pad facilities to detect losses from leaks and vents and has repaired all identified leaks. The repairs were carried out directly by the Corporation as part of its normal operations.

●

Enerplus uses water in the development of its assets in Canada and the U.S. During 2019, which is the latest available data, 74% of the Corporation’s water usage occurred in its Canadian operations, where 99% of the water is recycled and reused. The Corporation is exploring opportunities to reduce, reuse and recycle freshwater in its North Dakota completions operations, targeting a 15% reduction, on average, in freshwater use per well completion in 2020, relative to 2019 levels. Enerplus used, on average, 23% produced water in its 2020 completion program in North Dakota. The Corporation also established a 2025 goal to reduce freshwater use per well completion by 50% on a total company basis, relative to 2019.

GHG regulations have been enacted in certain states in the United States, in Saskatchewan and Alberta, and at the federal level in the U.S. and Canada. The Corporation is required to submit two reports under the Canadian federal Greenhouse Gas Reporting Program ("GHGRP") for its facilities that emitted more than 10,000 tonnes of carbon dioxide equivalent ("CO₂e") during 2019, and were submitted in June 2020.

For its operations in the United States, the Corporation is subject to the reporting requirement under the U.S. Environmental Protection Agency (the "U.S. EPA") Clean Air Act and the Mandatory Reporting of Greenhouse Gases Rule. The latest of these reports was submitted to the U.S. EPA on March 31, 2020 for the 2019 operational year. For more information on the environmental regulation applicable to the Corporation, see "Industry Conditions – Environmental Regulation".

In 2019, Scope 1 emissions of CO₂e were 954,520 tonnes. The Corporation expects its 2020 emissions (expected to be available in the second quarter of 2021) to be lower than 2019 as a result of its gas capture initiatives, combined with reduced activity levels due to the COVID-19 pandemic. Enerplus believes it is compliant with all relevant gas capture regulatory requirements. As a part of its ESG strategy, Enerplus has set a GHG emissions intensity reduction goal, based on Scope 1 and Scope 2 emissions, as defined by the GHGRP, of 10% per BOE for 2020 and a 2030 target of 50% lower per BOE, relative to 2019 levels. Based on preliminary estimates, Enerplus expects its GHG emissions intensity to be reduced by over 20%, relative to 2019 and its 2020 emissions intensity reduction target of 10% per BOE.

The Board's S&SR Committee regularly reviews health, safety, environmental and regulatory updates and risks. At present, the Corporation believes 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 and achieve its ESG targets

Overall, the Corporation strives to operate in a socially responsible manner and believes its health, safety and environmental initiatives and performance 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 material ESG focus areas to support this commitment and sets forth strategic goals and targets. The Corporation believes that by monitoring various lagging and leading metrics, identifying areas for improvement, and implementing strategies, processes and procedures in those material focus areas, the Corporation will continue to improve its S&SR and ESG performance. For more information on Enerplus’ ESG initiatives visit www.enerplus.com.

INSURANCE

The Corporation carries insurance coverage to protect its assets at 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 a number of risks including, but not limited to, third party liability, property damage, business interruption, pollution and well control. In addition, liability coverage is carried for the directors and officers of the Corporation.

The Corporation regularly commissions third-party loss prevention audits to identify and evaluate the risk exposures associated with production equipment, process operations, utility supply systems and natural hazards. The purpose of the loss prevention audits is to generate detailed loss prevention reports with risk-based recommendations for improving the overall safety and performance of the Corporation’s facilities, mitigating the potential exposure to financial loss associated with property damage and production loss, and ensuring the adequacy of its relevant insurance coverage. However, no loss prevention audits occurred in 2020 due to the COVID-19 pandemic.

34 ENERPLUS 2020 ANNUAL INFORMATION FORM

PERSONNEL

As at December 31, 2020, the Corporation employed a total of 360 persons, including full-time benefit employees and payroll consultants, 209 of whom were in Canada and 151 of whom were in the United States.

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, By-law No. 1 and By-law No. 2 were filed on January 2, 2013, June 16, 2014, and May 6, 2016, respectively, on the Corporation's SEDAR profile at www.sedar.com and on the Corporation's EDGAR profile at www.sec.gov.

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 contain provisions facilitating payment of dividends on Common Shares through issuance of Common Shares in circumstances where the board of directors declares, and a shareholder of the Corporation validly elects to receive, the payment of dividends, in whole or in part, in the form of Common Shares. See "Dividends – Stock Dividend Program".

PREFERRED SHARES

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

SENIOR UNSECURED NOTES

Enerplus has issued Senior Unsecured Notes, of which US$385.4 million principal amounts were outstanding at December 31, 2020. Certain terms of the Senior Unsecured Notes are summarized below:

Original

Remaining

Coupon

Interest

Issue Date

Principal

Rate

Payment Dates

Maturity Date

Term

September 3, 2014

US$200 million

US$105 million

3.79

March 3 and September 3

September 3, 2026

Principal payments required in five equal annual installments beginning September 3, 2022

May 15, 2012

US$20 million

4.40

May 15 and November 15

May 15, 2022

Bullet payment on maturity

May 15, 2012

US$355 million

US$238.4 million

4.40

May 15 and November 15

May 15, 2024

Principal payments required in four equal annual installments beginning May 15, 2021

June 18, 2009

US$225 million

US$22 million

7.97

June 18

June 18, 2021

Final installment on June 18, 2021

For additional information see "Material Contracts and Documents Affecting the Rights of Securityholders". See also Note 7 to the Financial Statements.

ENERPLUS 2020 ANNUAL INFORMATION FORM 35

BANK CREDIT FACILITY AND TERM FACILITY

As of December 31, 2020, the Corporation was undrawn on its US$600 million senior unsecured, covenant-based credit facility with a syndicate of financial institutions maturing October 31, 2023. For a description of the Bank Credit Facility, see Note 7 to the Corporation's Financial Statements. See also "Material Contracts and Documents Affecting the Rights of Securityholders".

On January 25, 2021, in connection with the Bruin Acquisition, the Corporation entered into the Commitment Letter providing for the Term Facility. The Corporation expects the Term Facility to be fully drawn down on the closing date of the Bruin Acquisition to pay for a portion of the Purchase Price. The Term Facility will include financial and other covenants substantially identical to those under the Bank Credit Facility, as well as similar pricing to the Bank Credit Facility. The Commitment Letter contains limited conditions to funding, including completion of the Bruin Acquisition substantially on the terms set forth in the Purchase Agreement and delivery of customary credit facility documentation. If the Bruin Acquisition is not completed, Enerplus will not enter into the Term Facility and will not have access to the US$400 million of funds available thereunder. See "General Development of the Business – Developments in the Past Three Years" and the Bruin Material Change Report.

Dividends

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 currently has established a dividend policy of paying monthly dividends to holders of Common Shares. The dividend record date is on or about the last business day of each calendar month and the corresponding dividend payment date is on or about the 15th day of the following 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 likely will 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 and other payments 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 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 2018, 2019, 2020 and January through March of 2021 (CDN$/share):


Month	2021		2020		2019		2018
January	$	0.01	$	0.01	$	0.01	$	0.01
February		0.01		0.01		0.01		0.01
March		0.01		0.01		0.01		0.01
April		N/A		0.01		0.01		0.01
May		N/A		0.01		0.01		0.01
June		N/A		0.01		0.01		0.01
July		N/A		0.01		0.01		0.01
August		N/A		0.01		0.01		0.01
September		N/A		0.01		0.01		0.01
October		N/A		0.01		0.01		0.01
November		N/A		0.01		0.01		0.01
December		N/A		0.01		0.01		0.01

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 were able to 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

36 ENERPLUS 2020 ANNUAL INFORMATION FORM

immediately prior to the applicable dividend payment date. Effective with the April 2014 dividend, the Corporation elected to eliminate the 5% discount applied to determine the number of Common Shares issued pursuant to the stock dividend program. Effective September 19, 2014, the board of directors of the Corporation suspended the stock dividend program to eliminate the dilution associated with the issuance of Common Shares through the program.

ENERPLUS 2020 ANNUAL INFORMATION FORM 37

Industry Conditions

OVERVIEW

The Corporation, and the oil and natural gas industry generally, are subject to extensive controls and regulation governing operations (including land tenure, exploration, development, production, refining, transportation, marketing, remediation, abandonment and reclamation) imposed by legislation enacted by various levels of government. The Corporation and the oil and natural gas industry are also subject to agreements among the various federal, state and provincial governments with respect to pricing and taxation of oil and natural gas. Although it is not expected 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 producers in similar operating areas, 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 Corporation’s participation in the oil and gas industry that are applicable to the Corporation’s operations.

The Corporation owns oil and natural gas properties and related assets in the United States (Montana, North Dakota, Pennsylvania and Colorado) and Canada (Alberta, Saskatchewan and British Columbia). The Corporation's oil and natural gas operations are regulated by a wide range of administrative agencies under statutory provisions of the states and provinces where such operations are conducted, by certain agencies of the federal government for operations on U.S. federal leases and, in some cases, by local agencies. These provisions regulate matters such as the exploration for and production of crude oil and natural gas, including rules 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 operations are also subject to various conservation laws and regulations in respect of 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, conservation laws sometimes establish maximum rates of production from crude oil and natural gas wells, generally prohibit or limit the venting or flaring of natural gas and associated liquids, and impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells.

The Corporation is required under Canada’s Extractive Sector Transparency Measures Act (“ESTMA”) to disclose payments made to governments of all levels, including First Nations in Canada and Indian Reservations in the United States. In addition, the Corporation will be required to furnish an annual report, or an alternative report complying with Canada’s ESTMA, to the SEC beginning in 2024 disclosing any payment made during the prior fiscal year by the Corporation to the U.S. government or a foreign government for the purpose of the commercial development of oil, natural gas, or minerals. These and other disclosure regulations could require us to incur significant costs, require us to disclose competitively sensitive commercial information, or cause us to violate non-disclosure laws or agreements, including those of the First Nations in Canada and Native American tribes within the United States.

PRICING AND MARKETING OF CRUDE OIL AND NATURAL GAS

In the United States and Canada, producers of crude oil negotiate sales contracts directly with crude oil purchasers. Most agreements are linked to continental or global oil prices, which are set by daily, weekly and monthly physical and financial transactions for crude oil around the world. Those prices are primarily based on overall fundamentals of supply and demand. Specific prices depend, in part, on crude oil quality, prices of competing fuels, distance to markets, access to downstream transportation, the value of refined products, the supply/demand balance and other contractual terms. In the United States, the Federal Energy Regulatory Commission (“FERC”) regulates rates and service conditions for interstate transportation of crude oil, which affect the marketing of crude oil, as well as revenues producers receive for sales of crude oil. Intrastate crude oil transportation service is also subject to regulation by some state regulatory agencies.

Producers of natural gas in the United States and Canada are free to negotiate prices and other terms with purchasers, provided export contracts meet certain criteria. In relation to U.S. exports, this would include restrictions on export licenses imposed by the United States Department of Energy, and in Canada, criteria prescribed by the Canadian Energy Regulator (previously the National Energy Board) and the Government of Canada. The prices depend, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to the market, access to downstream transportation, length of contract term, seasonal factors, weather conditions, the value of refined products, the supply/demand balance and other contractual terms. In the United States, the FERC regulates rates and service conditions for interstate transportation of natural gas, which affect the marketing of natural gas, as well as revenues producers receive for sales of natural gas. Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies.

Internationally, prices for crude oil and natural gas fluctuate in response to changes in the supply and demand for crude oil and natural gas, general market uncertainty and a variety of other factors beyond the Corporation's control. Crude oil and natural gas prices have experienced significant volatility during 2020 in response to a variety of factors including, among

38 ENERPLUS 2020 ANNUAL INFORMATION FORM

others, changes in the global supply of crude oil as a result of significant demand destruction resulting from the COVID-19 pandemic and, more generally, due to ongoing decisions by the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC members to manage production levels to achieve balance in crude oil supply and demand. See "Risk Factors – Oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on the Corporation's business, results of operations or cash flows and financial condition". In addition, crude oil and natural gas producers in some areas of North America currently receive discounted prices for their production relative to certain continental and/or international benchmark prices due to the lack of adequate egress which would allow crude oil and natural gas production to be transported and sold to national and, in some cases, international markets. See "Risk Factors – The inability to access land, inadequately developed infrastructure, and the impact of special interest groups on either, may result in a decline in the Corporation's ability to market its oil and natural gas production".

Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, crude oil, or other energy commodities and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess or seek civil penalties of up to $1,307,164 per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Failure to comply with the federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.

ROYALTIES AND INCENTIVES

In addition to federal regulations, each U.S. state and each province in Canada has legislation and regulations which govern oil and gas holdings and land tenure, royalties, production rates, environmental protection and other matters. In all U.S. jurisdictions, producers of oil and natural gas are typically required to make 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 on U.S. Indian leases are required to make annual rental payments regardless of well production, in addition to other fixed fees for land improvement, on a per well basis. The applicable royalty and production tax regime is a significant factor in the profitability of oil and natural gas production. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rentals and royalties in respect of Crown leases, and royalties and freehold production taxes in respect of oil and natural gas produced from freehold lands.

Royalties payable on production from lands other than federal and state lands in the United States and Crown-owned lands in Canada are determined by negotiations between the freehold mineral owner and the lessee. Federal, U.S. Indian, and state royalties and production taxes in the United States, and Crown royalties in Canada, 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 state governments in the United States and the federal and provincial governments in Canada have established incentive programs which have included royalty rate or production tax reductions (including for specific wells), royalty holidays, and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects. If applicable, oil and natural gas royalty holidays, reductions and tax credits would effectively reduce the amount of royalties paid by oil and gas producers to the applicable governmental entities.

LAND TENURE

Crude oil and natural gas located in the United States is predominantly owned by private owners. The U.S. Department of the Interior - Bureau of Land Management ("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

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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 ("FBIR") and involve allotee lands, which are lands that are administered by the Bureau of Indian Affairs ("BIA") but owned by individual tribal members. As such, these operations are governed by both state and federal regulations. U.S. federal departments such as the BIA, the BLM, and the U.S. EPA enforce the federal regulations. Federal U.S. regulations may differ significantly from regulations generally applicable to non-federally regulated lands and, as a consequence, may result in the slowing, or halting of, the Corporation's developments on the FBIR.

Crude oil and natural gas located in the western Canadian provinces are 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.

A lease generally may 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 jurisdiction has developed and adopted its own statutes that operators must follow both prior to and following drilling, including notification requirements and the obligation to provide compensation for lost land use and surface damage. 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 Corporation is subject to the applicable municipal, tribal, provincial, state and federal environmental laws and regulations in its operating areas in both Canada and the U.S. These requirements provide for environmental protection and impose restrictions and prohibitions regarding disturbances and releases or emissions of various substances produced or utilized in association with oil and gas industry operations. With respect to a property designated as a contaminated site, environmental laws may impose remediation obligations 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. In addition, legislation requires that well, pipeline and facility sites are abandoned and reclaimed to the satisfaction of the applicable authorities. 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. See "Risk Factors – The Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including those related to climate change, as well as public opposition and activism".

United States

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 BLM and the BIA for operations on public and tribal lands under the Federal Land Policy and Management Act and the U.S. EPA for operations under the National Environmental Policy Act. Environmental conservation and cultural and natural resources protection at the federal and state level are administered by numerous agencies under multiple statutes, codes, and regulations.

Planning, permitting and compliance related to environmental 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, emissions limitations and setbacks (buffers) for environmental and public health protection, which are imposed by several state agencies regulating oil and gas activities. In addition to the agencies which directly regulate oil and gas operations, there are other state and local conservation and environmental protection agencies that regulate air quality, water quality, aquatic biology, wildlife, land use, transportation, noise, spills and incidents, cumulative impacts, and impacts on disproportionately impacted communities.

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Additional regulations affecting the Corporation's U.S. operations include: (i) the Federal Implementation Plan for Oil and Natural Gas Well Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nations) (the "MHA Nation"), in North Dakota and (ii) the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. These regulations provide emission control requirements for the Corporation's U.S. assets, as well as increased monitoring, recordkeeping, reporting and regulatory oversight.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions, though federal agencies have asserted regulatory authority over certain aspects of the hydraulic fracturing process. For more information, see ”Risk Factors – The Corporation’s operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including but not limited to those related to climate change, as well as public opposition and activism”. All U.S. states in which the Corporation operates have regulations on hydraulic fracturing disclosure. The Corporation utilizes the internet-based chemical registry FracFocus both in Canada and the United States for posting of the required disclosure information. In the United States, 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 oil and gas industry and the Corporation utilizes the registry in all states and provinces in which it operates. Currently, FracFocus lists over 1,280 companies as registry participants.

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, BLM and certain state regulators have imposed restrictions on the flaring of natural gas.

The need for an operator to flare gas primarily stems from the fact that the rate of oil and gas development in North Dakota currently outpaces the construction of gas gathering and processing infrastructure. This situation is the result of various factors, including delays in obtaining right of way approvals, which is particularly cumbersome with respect to operations taking place on FBIR due to the application of additional regulatory requirements. The Corporation is working diligently with its midstream partner and the regulators to expand gas gathering capacity and increase gas capture rates. One measure being taken is the installation of NGL processing skids which are being used to extract NGLs from gas that would have otherwise been flared. See "Risk Factors - Higher than expected declines or curtailments in the Corporation's production due to infrastructure constraints, third party operational business practices or failures, or government regulation could have an adverse effect on results of operations or cash flows and financial condition". The Corporation did not receive any North Dakota Industrial Commission (“NDIC”) orders to curtail crude oil production in 2020, but NDIC gas capture requirements increased to 91% as of November 1, 2020.

The NDIC has adopted conditioning standards aimed at improving the safety of crude oil when transported. The regulation focuses on ensuring that produced crude oil is sufficiently conditioned at the well site to remove volatility characteristics that might pose unreasonable transportation hazards, regardless of the mode of transportation utilized. The Corporation has been in compliance with the NDIC conditioning standards requirements, which requires sampling and analysis twice per year, since their inception.

Other states have adopted similar or more stringent regulations for environmental protection. For example, Colorado has adopted sweeping changes to the states oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (“COGCC”) to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. In keeping with SB 19-181, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet instead of the previously required 500 feet) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, additional restrictions for oil and gas activities, such as requiring greater setbacks.

Implementation of more stringent environmental regulations on the Corporation's U.S. operations could affect the Corporation’s capital and operating expenditures and plans. The Corporation endeavours to reduce the potential of these impacts to U.S. operations in many ways, including through participation and membership in trade organizations such as the American Exploration and Production Council, North Dakota Petroleum Council, Montana Petroleum Association, Independent Petroleum Association of America, Western Energy Alliance and the Colorado Oil and Gas Association. In addition, the Corporation participates directly in legislative hearings, rulemaking processes, meetings with state officials and

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local stakeholder groups, and provides both written and verbal comments on proposed legislation and regulations. 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.

British Columbia

In British Columbia, all oil and gas operations are overseen by the British Columbia Oil and Gas Commission ("BCOGC"), primarily through the Oil and Gas Activities Act. The BCOGC also oversees compliance with a variety of environmentally-related statutes, including the Forest Act, Heritage Conservation Act, Land Act, Environmental Management Act and the Water Sustainability Act. The Corporation has one property in British Columbia which is subject to these regulations. The abandonment of this property began in 2019 and is expected to be completed by 2023. After completion of the abandonment, there will be ongoing work on reclamation and remediation through to and beyond 2024. All work is being completed in compliance with the BCOGC regulations.

Alberta

In Alberta, the Alberta Energy Regulator ("AER") is the single regulator of energy development in Alberta and oversees all aspects of the regulatory process, including application and exploration, construction and development, abandonment, reclamation, and remediation activities. The AER oversees compliance with the Oil and Gas Conservation Act, Public Lands Act, Mines and Minerals Act, Water Act and the Environmental Protection and Enhancement Act by oil and gas operators. In addition, Alberta Environment and Parks works to ensure the province's environmental, social and economic targets are met. This ministry is also responsible for climate change regulations such as the Alberta Technology Innovation and Emissions Reduction program.

Saskatchewan

In Saskatchewan, oil and gas exploration is overseen by the Ministry of Energy and Resources which administers legislation including The Crown Minerals Act, The Oil and Gas Conservation Act and The Pipelines Act, 1998. Environmental regulation is governed by the Ministry of Environment pursuant to the Saskatchewan Environmental Code, which consolidates rules under other statutes and, among other things, prescribes applicable levels of emissions without mandating express measures to achieve such levels. Saskatchewan's Ministry of Environment provides compliance and mitigation measures aimed at protecting the environment, It is responsible for regulations that oversee provincial climate change management such as the Output Based Performance Standard (“OBPS”) program which aims to reduce GHG emissions.

Climate change legislation

Globally, the shift to a low-carbon economy continues to shape ESG practices and business strategy, in particular with respect to climate change. Climate change legislation at each of the provincial, state and federal levels has the potential to significantly affect the oil and gas industry regulatory environment and impose significant operational and/or financial obligations on companies.

In addition, globally, the TCFD has been working to help identify information needed by investors, lenders and credit and insurance underwriters to appropriately assess and price climate-related risks and opportunities. Although not legislated in North America, the TCFD has developed voluntary disclosure under a singular, accessible framework specific to climate change. Four core recommendations have been presented which would apply to organizations across all sectors and jurisdictions. The four core areas of recommendation centre relate to governance, strategy, risk management and metrics and targets. An additional eleven detailed recommended disclosures have been made, along with the call for the reporting of decision-useful information in mainstream filings. Enerplus recognizes the TCFD recommended guidelines and is working toward integrating fit for purpose disclosure from the guidelines into its ESG strategy and future reporting.

Both Canada and the United States were part of the United Nations Framework Convention on Climate Change ("UNFCCC") meeting in Paris in 2015. A binding commitment, (the “Paris Agreement”), was signed by all panel countries that set a target of no more than a two-degree Celsius warming of the earth based on GHG levels in the atmosphere. This commitment to limit warming may increase provincial, state and federal GHG regulatory rigour as country-level emissions will be reviewed periodically in subsequent meetings to assess alignment with the targets agreed upon. The agreement also called for countries to submit non-binding, individually-determined emissions reduction targets every five years after 2020. While the United States withdrew from the Paris Agreement under former President Trump’s Administration, effective November 4, 2020, President Biden has issued executive orders recommitting the United States to the Paris Agreement and calling for the federal government to formulate the United States’ emissions reduction target. With the United States recommitting to the Paris Agreement, further executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the agreement’s goals.

Additionally, the U.S. EPA continues to enforce GHG emissions regulations pursuant to the Clean Air Act that establish a reporting program for CO2, methane and other GHG emissions. It has also established a permitting program for certain

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large GHG emissions sources. There has been considerable uncertainty surrounding regulation of methane emissions in the United States, as the U.S. EPA under former President Obama’s Administration published final regulations under the Clean Air Act establishing new source performance standards (“NSPS”) for reduction of methane from certain new, modified or reconstructed oil and gas facility sources in 2016, but since that time the U.S. EPA under former President Trump’s Administration has undertaken several measures to delay or restrict implementation of those standards, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and VOC requirements for the remaining sources that were established by former President Obama's Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. Various states and industry and environmental groups are separately challenging the U.S. EPA’s 2016 standards and its September 2020 final rules and on January 20, 2021, President Biden issued an executive order, that among other things, directed the U.S. EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. While the United States Congress has considered numerous legislative initiatives to reduce or tax GHG emissions, to date no laws in that regard have been enacted. On a state level, some states have enacted laws concerning GHG emissions, including increased stringency of emissions standards or the imposition of regulatory markets that require certain limits on GHG emissions.

The Government of Canada is working toward the two-degree target on a sector by sector basis but has yet to finalize regulations pertaining to the oil and gas sector. As part of its commitment under the Paris Agreement, the Canadian federal government developed the Pan-Canadian Framework on Clean Growth and Climate Change (the "Framework") in 2016, together with provincial (except Alberta, Saskatchewan, Ontario and Manitoba as these provinces have announced their intention to withdraw) and territorial leaders in consultation with Canada's Indigenous Peoples, to meet Canada’s emission target while enabling economic growth.

Under the Framework, the Canadian federal government requires that all jurisdictions adopt the Federal Fuel Charge or develop a carbon pricing system that is equivalent to $20/tonne in 2019 and rising by $10 per year to $50/tonne in 2022 and beyond. Jurisdictions can implement: (i) an explicit price-based system (such as the carbon levy and performance-based emissions system adopted in Alberta), or (ii) a cap-and-trade system (which has been adopted in Ontario and Quebec). Within these programs, provinces have discretion to manage competitiveness of their trade-exposed industries. In June of 2018, the Government of Canada's federal carbon pricing system, entitled the Greenhouse Gas Pollution Pricing Act ("GHGPPA") received royal assent. The GHGPPA is only intended to act as a regulatory backstop in the event a province or territory does not otherwise implement an adequate GHG regime. On December 11, 2020, the federal government announced a plan called "A Healthy Environment and A Healthy Economy" which outlines intentions to increase the federal carbon tax rate to $170/tonne by 2030.

The Province of Saskatchewan has objected to implementing a carbon tax in its jurisdiction and, therefore, since 2019 it has been considered a backstop province and requires the Federal Fuel Charge be imposed on its industries. The Province of Saskatchewan believes its climate change plan, which does not include a carbon tax, is sufficient to reduce emissions and has submitted its carbon tax appeal to the Supreme Court of Canada. Saskatchewan's Management and Reduction of Greenhouse Gas (Standards and Compliance) Regulations were amended in October 2020 to allow for companies with stationary fuel combustion emissions of under 10,000 tonnes of CO₂e to voluntarily opt into the OBPS program in 2021. The Corporation received approval in January 2021 to participate in the OBPS program, which provides an exemption from paying the Federal Fuel Charge at its Saskatchewan facilities. The program requires an emissions intensity reduction of 1.25% each year, to culminate in a 15% reduction in total by year twelve (2033). In 2020, the Corporation paid approximately $337,449 in Saskatchewan.

On May 30, 2019, the Government of Alberta repealed the Climate Leadership Act, which imposed a carbon levy on consumers for GHG emissions arising from the combustion of fuels for heating and transportation. In doing so, the Federal Fuel Charge has also been imposed on industries in the Province of Alberta. In response to mitigating the Federal Fuel Charge, on October 29, 2019, the Government of Alberta announced its Technology Innovation and Emissions Reduction Regulation ("TIER"), which regulates large facilities emitting more than 100,000 tonnes of CO₂e, and allows for voluntarily opt-in. Facilities regulated under TIER are subject to a 10% emission intensity reduction obligation, providing companies operating in Alberta, including Enerplus, with protection from the Federal Fuel Charge at this time. In 2020, the Corporation paid approximately $337,449 in Saskatchewan and $86,383 in British Columbia for carbon tax levies.

The Supreme Court of Canada has not yet issued its decision from the September 2020 hearings regarding the Saskatchewan, Alberta and Ontario governments' challenges of the constitutionality of the Federal Fuel Charge.

The Canadian federal government also issued Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Regulations") in April of 2018. The intent of the

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Regulations is to reduce methane emissions by 40% to 45% below 2012 levels by 2025. These Regulations become applicable in any province or territory that chooses not to develop equivalent regulations. The Regulations have two stages of implementation: Stage 1 (leak detection and repair, venting from well completions and compressors), which will be in effect in 2020 and Stage 2 (venting restrictions and pneumatics), which will be in effect in 2023. The provinces of Alberta and Saskatchewan achieved equivalency with the federal requirements in 2020, with the result that the relevant provincial requirements are in effect for and apply to the Corporation.

The Province of Alberta has established a methane emissions reduction goal of 45% by 2025. To achieve that, in December 2018 the AER issued prescriptive measures to reduce methane emissions by implementing design standards on new facilities, addressing venting limits from new and existing equipment, and increasing requirements regarding fugitive emission surveys and reporting. These measures intend to achieve equivalency with the federal methane regulations issued in April 2018. The Corporation estimates it could incur up to an additional $300,000 annually for equipment retrofits, increased measurement and reporting work, and higher frequency of fugitive leak inspections.

In May of 2010 the Province of Saskatchewan’s The Management and Reduction of Greenhouse Gases Act ("GHG Act") received royal assent with only certain portions proclaimed in force on January 1, 2018. The Province of Saskatchewan has established a goal of reducing GHG emissions from the province’s upstream oil and gas sector by 40% to 45% from 2015 levels by 2025. In December of 2017, the Government of Saskatchewan released a climate change strategy entitled Prairie Resilience: A Made in Saskatchewan Climate Change Strategy (the "Strategy") to affirm provincial regulatory jurisdiction over emissions regulation. This Strategy focuses on sector-specific approaches and climate change adaptation. The Government of Saskatchewan has publicly stated that the Saskatchewan regulatory package provides an alternative, robust plan to the federal GHG emission reduction regulations to help Saskatchewan achieve climate change goals, while also providing industry with the flexibility to implement measures in an effective, economically viable way. Pursuant to the Strategy, the Province of Saskatchewan released The Oil and Gas Emissions Management Regulations (the "OGEMR"), which came into effect January 1, 2019 and are applicable to entities whose potential total emissions from gas production are greater than 50,000 tonnes of CO₂e per year. In 2020, the Corporation’s potential total emissions were 44,172 tonnes, which is below the criteria to be regulated under OGEMR.

The Corporation has not experienced a material adverse effect from requirements to comply 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 costs of both a capital and expense nature as a result of increasingly stringent 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, including those related to climate change, as well as public opposition and activism” and "Risk Factors – Government policy and/or regulations and required regulatory approvals and compliance may adversely impact the Corporation's operations and result in increased operating and capital costs".

WORKER SAFETY

The Corporation’s 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 incident reporting procedures, also requires every employer to ensure 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. The Corporation is currently in compliance with applicable safety legislation.

Risk Factors

The following risk factors, together with other information contained in this Annual Information Form and other filings, including the Corporation’s MD&A, and its Financial Statements and related notes, should be carefully considered before investing in the Corporation. Each of these risks may negatively affect the trading price of the Common Shares, the number of Common Shares that may be repurchased by the Corporation, 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.

Please note, all references to “natural gas” in this section refer to both natural gas and shale gas.

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Oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on the Corporation's business, results of operations, or cash flows 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. These price fluctuations have been and could occur in response to a variety of factors beyond the Corporation's control, including:

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global energy supply and demand, production and regulatory policies

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actions taken by OPEC or non-OPEC members to set, maintain, or alter production levels

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geopolitical uncertainty, including for example, E.U. stability and U.S.-China relations, the change in U.S. federal government, the risk of hostilities in the Middle East and global terrorism, as well as actions taken within the U.S. or Canada that could disrupt trade or other relations

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sustained pandemics/epidemics, including the COVID-19 pandemic, that disrupt economies, whether local or global, impacting supply, demand or commodity prices for crude oil, NGLs or natural gas and anticipated crude oil and natural gas price recoveries

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global and domestic economic conditions, particularly as a result of potential fiscal crises driven by debt, as well as currency fluctuations

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the level of consumer demand, including demand for different qualities and types of crude oil, NGLs and natural gas

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the production and storage levels of North American natural gas and crude oil, and the supply and price of imported or exported crude oil and liquefied natural gas

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weather conditions

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the proximity of reserves and resources to, and capacity of, transportation facilities, and the availability of refining, processing and fractionation capacity

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the ability, considering regulation, taxation, and market demand, to export crude oil and liquefied natural gas and NGLs from North America

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the impact of world-wide energy conservation and decarbonization efforts, GHG reduction measures, and the price and availability of alternative fuels

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existing and proposed changes to government regulations and policy decisions, including moratoriums with respect thereto

Oil and natural gas producers in North America may receive significantly discounted prices for some of their production due to regional constraints on the ability to transport and sell such production to international markets. Additionally, limited natural gas and NGLs processing capacity or other infrastructure constraints may result in producers not realizing the full price for their production. The inability to resolve such constraints may result in continued reduced commodity prices received by oil and natural gas producers such as the Corporation.

Future declines in crude oil and/or natural gas prices, or an extended low commodity price environment, may have a material adverse effect on the Corporation's operations and cash flows, 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 proceed with as part of the Corporation’s exploration or development plans or projects if commodity prices are low, thereby impacting the Corporation's production volumes. Low prices may also impact the Corporation’s desire to market its production under unsatisfactory market conditions. Alternatively, due to regulatory or contractual obligations, the Corporation may be required to produce from or develop certain properties to fulfill its obligations despite unsatisfactory market conditions for marketing of any production therefrom, increasing the risk of financial losses. Furthermore, the Corporation may be subject to the decisions of third party operators who, independently and using different economic parameters than the Corporation, may decide to curtail or shut-in jointly owned production.

The Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including but not limited to those related to climate change, as well as public opposition and activism.

GENERAL

The oil and natural gas industry elicits concerns about climate change, as well as general public opposition to the industry. As a result, industry participants may be subject to increased public activism, as well as extensive environmental regulation pursuant to local, provincial, and federal legislation in Canada and federal and state laws and regulations in the United States. Activist activity by environmental groups, for example, may result in increased costs due to delays or damage. Existing and future laws and regulations may impose additional costs on companies operating in the oil and gas industry or significant liabilities for failure to comply with the requirements. Concerns over climate change and fossil fuel extraction could lead governments to enact additional or more stringent laws and regulations applicable to the Corporation and other companies in the energy industry in general. Any defaults by the Corporation under the applicable legislation could result

ENERPLUS 2020 ANNUAL INFORMATION FORM 45

in the imposition of fines or the issuance of "clean up" orders. As the form of such legislation and regulations continues to evolve, specific financial and operational outcomes are not clearly identifiable.

Generally, the business of exploration, development and production of oil and natural gas wells and facilities is subject to the risks and hazards associated with such operations. These include, but are not limited to, blowouts, fire, explosion, environmental releases (including sour gas), induced seismicity, and other safety hazards, which could result in significant damage to the Corporation’s property, personal injury, loss of life, and liability to regulators or third parties. In addition, general public and government opposition toward the oil and gas industry, including the shift to world decarbonization, could reduce demand for oil and gas and, therefore, adversely affect market prices for production, as well as the financial and operating results of the Corporation.

The Corporation is not fully insured against all 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 damage) 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 for development of projects and resources, debt repayments, or as available cash for dividends to shareholders. Enerplus has estimated the present value of its future asset retirement obligations to be $130.2 million at December 31, 2020 (see its Financial Statements) the majority of which it expects to incur between 2024 and 2046. Further, the availability in some jurisdictions of monies collected via levies on oil and gas producers, in order to cover remediation and/or reclamation costs incurred by the Corporation on behalf of insolvent or defunct partners, may be reduced or eliminated as such funds become depleted. 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 CLIMATE CHANGE

As noted, public support for climate change action has grown in recent years, as has the receptivity to employing new technologies to address the same. Governments in the United States, Canada and around the world have responded to these shifting societal attitudes by adopting ambitious emissions reduction targets and supporting legislation, including measures relating to carbon pricing, clean energy and fuel standards, and alternative energy incentives and mandates. At the international level, the United Nations-sponsored Paris Agreement requires nations to submit non-binding, individually-determined emissions reduction targets every five years after 2020. While the United States withdrew from the Paris Agreement under former President Trump’s Administration, effective November 4, 2020, President Biden has issued executive orders recommitting the United States to the Paris Agreement and calling for the federal government to formulate the United States’ emissions reduction target. With the United States recommitting to the Paris Agreement, further executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the agreement’s goals.

The major climate change-related risks are generally grouped into two categories: physical risks and transition risks. Physical risks are those that a change in climate itself could have on a business (e.g., as a result of a fire or flooding). Transition risks are broader and generally describe those risks related to the consequences of a global transition to reduced carbon. Specifically, transition risks encompass risks of regulatory and policy changes, as well as reputational concerns.

Physical Risks

Enerplus does not believe that its current operations expose it to any material physical risks which differ from those facing North American onshore oil and gas producers, and currently cannot predict or quantify the potential financial impact of any such risks. However, certain risks, such as water availability or the impact of severe weather, could negatively impact operations and production, leading to additional costs which could impact Enerplus’ economics and profitability.

Transition Risks - Regulatory and Policy

The growing push for decarbonization increases the risk of potentially burdensome regulatory and/or policy changes that could impede the Corporation's access to service providers, lenders, insurers and the investment community. In addition, the Corporation could also be unable to obtain value for, or from, its properties. More specific concerns of the fossil fuels industry relate to GHG emissions, as well as water and land use, could also result in more stringent legislation or regulation, including requirements to significantly reduce GHG emissions, water consumption, or setback requirements for facilities and wells, all of which could result in increased implementation costs. For example, on January 27, 2021, President Biden

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signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the United States federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Failure to comply with such regulations and laws could also result in significant penalties being imposed. In addition, a potential increase in capital expenditures, operating expenses, abandonment and reclamation obligations and distribution costs, or the loss of operating licenses, any of which may not be recoverable in the marketplace, could also result in operations or growth projects becoming less profitable, uneconomic, or result in the Corporation’s inability to continue the development of its properties. Additionally, there is a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector; both the Bank of Canada and the Federal Reserve of the United States have joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. The adoption of new technologies to address these issues could also require a significant investment in capital and resources, therefore negatively impacting results and economics. For a more detailed discussion on regulatory risks for Enerplus, please see “Supplemental Operational Information” and “Industry Conditions – Environmental Regulation”.

Transition Risks – Reputational

A component of Enerplus’ strategy is to be a “best in basin” operator – in the eyes of its shareholders, employees, contractors, regulators, communities and the general public. However, activities undertaken directly by the Corporation or its employees, or by others in industry, could adversely affect Enerplus’ reputation. For example, there has been an increase in activist activity in Canada and the United States, including threats of culpability, and legal action against other oil and gas producers, as well as public opposition to fossil fuels and the oil and gas industry in which the Corporation operates due to negative public perceptions related to pipeline operator incidents, unpopular expansions or new projects, none of which are necessarily controlled by the Corporation but have the potential to impact the Corporation given the industry-linked association. See “— The inability to access land, inadequately developed infrastructure, and the impact of special interest groups on either, may result in a decline in the Corporation's ability to market its oil and natural gas production".

If the reputation of the Corporation, or the oil and gas industry in general, is diminished, it could result in: the loss of employees, or revenue; delays in regulatory approvals; increased operating, capital, financing, insurance and regulatory costs; reduced shareholder confidence and negative stock price movement; negative relationships with Indian Reservations and Indigenous groups; or a loss of public support in general.

RISKS RELATING TO FRACTURING

The Corporation utilizes horizontal drilling, multi-stage hydraulic fracturing, specially formulated 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 fluids and the volume of fluid 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 governments, including certain U.S. state and Canadian provincial governments, may review 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, the Biden Administration issued an order temporarily suspending the issuance of new leases and authorizations on federal lands and waters for a period of 60 days from January 20, 2021, and subsequently issued a second order in January 2021 suspending the issuance of new leases on federal lands and waters pending completion of a study of current oil and gas practices. Although these suspensions do not limit existing operations under valid leases and are not applicable to tribal lands that the federal government holds in trust, further constraints may be adopted by the Biden Administration in the future. Separately, President Biden has issued an executive order that commits to substantial action on climate change, calling for, among other things, the elimination of subsidies provided to the fossil fuel industry and an increased emphasis on climate-related risks across government agencies and economic sectors. President Biden may pursue additional executive orders, new legislation and regulatory initiatives to further implement his regulatory agenda. Additionally, 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. Claims have been made that hydraulic fracturing techniques are harmful to surface water and drinking water sources and may contribute to earthquake activity, particularly where operators are in proximity to pre-existing faults. Governmental authorities in jurisdictions where the Corporation does not currently operate have either implemented or considered temporary moratoriums on hydraulic fracturing until further studies can be completed, and some governments, including the United States, have adopted or 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,

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the implementation of new laws, regulations or permitting requirements with respect to water usage or disposal, or hydraulic fracturing generally, could increase the Corporation's costs of 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.

Government policy and/or 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, various environmental protection controls, well and facility design and operation, income, the exportation of crude oil, natural gas and other products, and 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, the imposition of production curtailments, control over the development and abandonment of fields (including restrictions on production), restrictions on the combustion of natural gas and possibly expropriation or cancellation of contract rights. See "Industry Conditions". To the extent the Corporation fails to comply with applicable government regulations or regulatory approvals, the Corporation may be subject to compliance and enforcement actions that are either remedial, which are intended to fix the non-compliance and any related impacts, or punitive, which are intended to deter future non-compliance. Such actions include fines or fees, notices of non-compliance, warnings, orders, administrative sanctions, and prosecution. In addition, obstructive tactics which could prevent certain measures from being voted upon in the United States legislature, or any government action resulting in a prolonged government shutdown, may impact the Corporation as a result of its inability to obtain regulatory and other approvals.

Government regulations may be changed from time to time in response to economic, political, or socioeconomic conditions. 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. U.S. federal and state and Canadian federal and provincial governments continue to scrutinize emissions, as well as the usage and disposal of chemicals and water used in fracturing procedures in the oil and gas industry; certain states have called for bans on oil and gas drilling using hydraulic fracturing. More activity by the Corporation on Indian lands in the United States, or lands held by Indigenous groups in Canada, may also increase compliance obligations under tribal or local 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, or restrict the supply of, crude oil and natural gas production, 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, or have implemented, legislation to reduce emissions of greenhouse gases, including volatile organic compounds. See "Industry Conditions – Environmental Regulation" for a description of these initiatives. Because the Corporation's operations emit various types of GHGs, such new legislation or regulations 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 GHG emissions, shut-in production, pay taxes, fees and other penalties related to its GHG emissions, and administer and manage a GHG emissions program. Currently, the Corporation is not able to estimate such increased costs; however, they could be material. Any of the foregoing could have adverse effects on the Corporation's business, financial position, results of operations and prospects.

Recent changes in U.S. administration may restrict the Corporation's operations in certain areas of the United States.

The recent changes in control of the U.S. Congress and the election of President Biden may result in legislative and regulatory changes that could have an adverse effect on the Corporation. In particular, President Biden has indicated that his administration will seek to curtail hydraulic fracturing on federal lands, possibly through delays or bans on the issuance of drilling permits, and his administration may pursue other regulatory initiatives, executive actions and legislation in support of his regulatory agenda. The Corporation's operations in most jurisdictions require permits from one or more governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. In the United States, such permits are typically issued by state agencies, but U.S. federal and local governmental permits may also be required. In addition, some of the Corporation's drilling and completion activities in the United States may take place on U.S. federal land or Native American lands, requiring leases and other approvals from the U.S. federal government or Native American tribes to conduct such drilling and completion activities. Under certain circumstances, U.S. federal agencies may refuse to approve new leases for hydrocarbon exploration and development on federal lands, and may refuse to grant or delay approvals required for development of existing leases. The Biden Administration issued an order temporarily suspending the issuance of new leases and authorizations on federal lands and waters for a period of 60 days from January 20, 2021, and subsequently issued a second order in January 2021 suspending the issuance of new leases on federal lands and waters pending completion of a study of current oil and gas practices. Although these suspensions do not limit existing operations under valid leases and are not applicable to tribal lands that the federal government holds in trust, further constraints may be adopted by the Biden Administration in the future. To the extent that the Corporation's operations in certain areas of the United States are restricted, delayed for varying lengths of time or cancelled, such developments may

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have a material adverse effect on the Corporation's results of operations and financial condition. In addition, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Climate Agreement, which could result in additional U.S. executive orders or U.S. federal legislation or regulatory initiatives in a purported effort to achieve the agreement's goals. In addition, there is uncertainty regarding U.S. support for existing treaty and trade relationships with other countries, including Canada, as evidenced by President Biden's executive order on January 20, 2021 revoking the permit for the Keystone XL Pipeline. Implementation by the U.S. government of new legislative or regulatory policies could impose additional costs on the Corporation, decrease U.S. demand for the Corporation's products, or otherwise negatively impact the Corporation, which may have a material adverse effect on the Corporation's business, financial condition and operations. In addition, this uncertainty may adversely impact (a) the ability or willingness of Canadian companies to transact business with companies such as the Corporation; (b) the Corporation's profitability; (c) regulation affecting the U.S. and Canada; (d) global stock markets (including the TSX); and (e) general global economic conditions. All of these factors are outside of Enerplus' control, but may nonetheless lead the Corporation to adjust its strategy in order to compete effectively in global markets.

The inability to access land or use existing infrastructure, or adequately develop infrastructure, including as a result of the impact of special interest groups, may result in a decline in the Corporation's ability to operate and market its oil and natural gas production.

The Corporation's business depends in part upon the ability to access its lands to operate, as well as the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and/or rail transportation systems and processing facilities to provide access to markets for its production. U.S. federal and state, as well as Canadian federal and provincial regulation of oil and natural gas production and processing and transportation could adversely affect the Corporation's ability to produce and market crude oil, natural gas and NGLs. Special interest groups and/or social instability could prevent access to leased land or continue its opposition to infrastructure development, at either the regulatory or judicial level, including the ongoing matters with respect to DAPL (which are before the United States District Court for the District of Columbia ("District Court")), resulting in operational delays, or even cancellation of construction of the required infrastructure or the shutdown of already operating infrastructure projects, any of which frustrate the Corporation’s ability to operate, produce and market its products. In addition, the assets of the Corporation are concentrated in regions with varying levels of government regulations, or under tribal or local rules that could result in the imposition of a limit or ban on shipping of commodities by truck, pipeline or rail.

OIL AND NATURAL GAS GATHERING SYSTEMS

Development of new resource plays generally results in a sharp increase in the volume of oil and natural gas being produced in the area, which could exceed government-regulated gas capture requirements, or the existing capacity of the various gathering system infrastructure. The Corporation relies on the timely construction of adequate gathering systems that allow its crude oil and natural gas production to be transported from the wellhead to existing and/or new sales infrastructure systems, such as pipelines or rail terminals.

The pace at which producer or midstream companies can construct adequate gathering infrastructure to capture the natural gas associated with the development of crude oil and NGLs properties may have an impact on the Corporation’s ability to increase crude oil production in its producing regions. Additionally, as exploration and drilling in these regions increases, the amount of natural gas being produced by the Corporation and others could exceed the capacity of the various gathering pipelines available in those areas. If these constraints remain unresolved, the Corporation's ability to transport its production to sales pipelines in these regions may be impaired and could adversely impact the Corporation's production volumes or realized prices in these areas. In the United States, the distinction between federally unregulated natural gas gathering facilities and FERC-regulated natural gas transmission pipelines under the Natural Gas Act (“NGA”) has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis. Consequently, the classification and regulation of gathering facilities that we transport our product on could change based on future determinations by the FERC, the courts or the United States Congress. If these gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we pay for service on the affected facilities.

SALES PIPELINES AND RAIL TRANSPORTATION SYSTEMS

Oil and natural gas producers in certain regions of North America may receive significantly discounted prices relative to benchmark prices for their production due to constraints on the ability to transport and sell such production to domestic and international markets. While oil and gas transportation infrastructure generally expands capacity to meet market needs, there can be differences in timing in the growth of such capacity. This is currently the case with natural gas and crude oil sales pipelines in certain areas where the Corporation has operations, as there are cases of inadequate sales pipeline capacity to transport production out of these regions, which may result in volume curtailments and low regional commodity prices. Unfavourable economic conditions or financing terms, as well as significant delays in the regulatory approval process, may defer or prevent the completion of certain pipeline projects, gathering systems or railway projects that are planned for such areas. There may also be operational or economic reasons, including but not limited to maintenance activities, for curtailing transportation capacity. In addition, there could be legal or regulatory challenges by third parties on

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existing sales pipelines, which could impact a pipeline’s ability to provide services to shippers. Accordingly, there can be periods where transportation capacity is insufficient to accommodate all the production from a given region, causing added expense and/or volume curtailments for all shippers. To the extent that the transportation capacity becomes insufficient in areas where the Corporation operates, the Corporation may have to defer the development of, curtail production from or shut-in wells awaiting a pipeline connection or other available transportation capacity, and/or sell its production at lower prices than it would otherwise realize or it had projected to realize. This would adversely affect the Corporation's results of, and cash flow from, operations.

A portion of Enerplus' production from the Williston Basin is delivered either directly or indirectly for transport to DAPL. Although the Corporation's products may be delivered for transport to other pipelines, a shutdown of DAPL or any other significant pipeline providing transportation services from the Williston Basin may adversely impact the Corporation's ability to obtain sufficient capacity on those pipelines at an effective cost. In 2016, several Sioux tribes filed a lawsuit in the District Court challenging authorizations issued by the United States Army Corps of Engineers ("USACE") to DAPL for operations near the Missouri River. In July 2020, the District Court vacated the USACE’s grant of an easement to DAPL and issued an order requiring DAPL to be shut down and emptied of oil by August 5, 2020, pending an Environmental Impact Statement (“EIS”) for the pipeline. However, this order was stayed by the Court of Appeals for the District of Columbia in early August, pending the outcome of the appeals process. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement and the requirement to prepare an EIS but declined to require the pipeline to shutdown while the EIS is prepared. The Court of Appeals implored the USACE to promptly consider if and how it may deal with the vacatur of the easement and left open the possibility for the USACE to order the pipeline shut in for lack of an easement. USACE has formerly stated that it considers the presence of the pipeline without an easement to constitute an encroachment on federal land and that it is considering whether to exercise its enforcement discretion regarding this encroachment. Additionally, the District Court is actively considering whether to enjoin the operation of the pipeline due to the lack of an easement; however, the District Court has not yet ruled on this matter. DAPL continues to operate pending a decision by the District Court or USACE to require the pipeline to cease operations, and Enerplus cannot determine when or how these matters will be resolved or the impact they may have on DAPL. Any ruling or regulatory decision that restricts the availability of pipeline capacity for offtake from the Williston Basin may materially adversely effects Enerplus' future operational results in that basin.

The Corporation has the ability to transport its crude oil production by a diverse mix of pipeline, trucking and, if necessary, rail (after title is transferred to the buyer’s name), all of which are subject to various risks of cost escalation and/or new costs. In certain regions the Corporation is currently dependent upon only one means of transportation. With respect to rail transportation, there may be future incremental costs associated with transporting, and risks that access to rail transport may be constrained, depending upon changes made to existing rail transport regulations. More stringent government regulations concerning the usage of certain types of tank cars that transport crude oil and NGLs by rail in the United States and Canada have been enacted, and this could increase the cost of utilizing rail to transport crude oil and/or NGLs. In addition, crude oil and natural gas volumes being shipped by pipelines are required to meet certain quality specifications, which vary by pipeline. Should crude oil, natural gas or NGLs quality specifications fail to be met by a producer that is shipping volumes on a pipeline, the pipeline could shut down or curtail volumes of other producers shipping on that pipeline. Any shutdown, curtailment, reversal of pipeline flow, or a change in the commodity being transported on pipelines shipping volumes of the Corporation’s production may impact the Corporation’s ability to reach its intended market, or deliver fully on its obligations.

ACCESS TO PROCESSING FACILITIES

NGLs production requires processing at fractionation facilities to separate the liquids stream into individual saleable products. The Corporation and the industry rely on the addition of adequate fractionation capacity to ensure the timely and economic processing of NGLs and the continued production of crude oil and natural gas associated with those liquids. Limited natural gas processing capacity in certain regions may result in producers not realizing the full price for NGLs associated with their natural gas production.

Crude oil and natural gas production requires processing at certain facilities in order to be transported on regional pipeline systems. The Corporation and the industry rely on the addition of adequate natural gas and other processing capacity to ensure the timely and economic processing of natural gas production, and the continued production of crude oil and NGLs, as well as any associated natural gas production. Limited natural gas processing capacity in certain regions may result in producers not being able to sell some or all of their natural gas production, lead to curtailment of crude oil production, or result in not realizing the full value of their natural gas production.

A failure to resolve any of the constraints described above may result in the Corporation failing to comply with certain environmental regulations, shutting-in production, or receiving continued reduced commodity prices.

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Higher than expected declines or curtailments in the Corporation’s production due to infrastructure constraints, third party operational business practices or failures, or government regulation could have an adverse effect on results of operations or cash flows and financial condition.

Continued industry production growth for any of the Corporation’s products may exceed the capacity of existing pipeline infrastructure until debottlenecking is undertaken or completed. During such periods, regional prices may decline to levels where the Corporation considers, or governments mandate, curtailment of production. In some cases, alternate shipping methods, such as rail for crude oil, may be used and could result in higher costs and lower netbacks. In addition, the continuing production from a property, and to some extent the marketing of that production, is dependent upon the abilities of the operators of the Corporation's properties. A significant portion of the Corporation's production is from properties operated by third parties. This results in significant reliance on third party operators in both the operation, including the decision to curtail production due to low prices, and the development of such properties.

Operating agreements governing properties not operated by the Corporation typically require the operator to conduct operations in a “good and workmanlike" manner. These operating agreements generally exempt the operator from liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except for liabilities that may result from the operator’s gross negligence or wilful misconduct. To the extent a third-party operator fails to perform its duties properly, faces capital or liquidity constraints or becomes insolvent, the Corporation's results of operations may be negatively impacted.

The timing and amount of capital required to be spent by the Corporation may also differ from the Corporation's expectations and planning, and may impact the ability of and/or cost to the Corporation to finance such expenditures, as well as adversely affect other parts of the Corporation's business and operations.

As a result of the foregoing, the Corporation may be required to curtail or shut-in production, which could damage a reservoir and potentially prevent the Corporation from achieving production and operating levels that were in place prior to the curtailment or shutting-in of the reservoir. In addition, the lower levels of production could result in a material reduction to the Corporation’s cash flow, or may result in the Corporation incurring additional operating and capital costs for the well(s) to achieve prior production levels.

An increase in capital or operating costs could have a material adverse effect on results of operations or cash flows and financial condition.

Higher capital or operating costs associated with the Corporation's operations will directly impact its capital efficiencies and/or decrease the amount of the Corporation's cash flow. Capital costs of completions, specifically the costs of proppant, pumper services, and operating costs such as electricity, chemicals, supplies, processing charges, energy services and labour costs, are a few of the Corporation's costs that are susceptible to material fluctuation. Although the Corporation has a portion of its current capital and operating costs protected with existing agreements, changing regulatory conditions, such as potential new or revised regulations in the U.S. requiring certain raw materials, such as steel, for use on certain projects to be sourced from the U.S., or that goods and/or services be procured from specific vendors or classes of vendors on certain projects, may result in higher than expected supply costs for the Corporation.

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

In the normal course of making capital investments to maintain and/or 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 to reduce debt, complete acquisitions, and maintain a more optimal capital structure. The Corporation may also divest of existing properties or assets 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, become limited, unavailable or available on less favourable terms, the Corporation's ability to make the necessary capital investments to: (i) retain leases, (ii) carry out its operations, and/or (iii) maintain and/or expand its oil, NGLs and natural gas reserves and resources could be adversely affected. 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 scope of activities and participation in the capital markets may attract increased criticism, shareholder activism and costly litigation.

The Corporation's business activities, both geographically and with a focus on exploration and development of unconventional reservoirs, may draw increased attention from shareholder activists who oppose the strategy of the Corporation, including its operation of the business, its plans for development and its capital allocation decisions, which could have an adverse effect on market value. In addition, such activists could become shareholders with significant

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influence or control, specifically to meet activist objectives. The Corporation’s ongoing participation in the Canadian and U.S. capital markets may expose the Corporation to greater risk of class action lawsuits related to, among other things, securities law matters (including with regard to alleged deficiencies in the Corporation’s public disclosure or inadequate governance), title, contractual and environmental matters (including climate change). In addition, the Corporation may, from time to time, be subject to material disputes, mediation, arbitration and litigation involving counterparties and other stakeholders the Corporation interacts with, directly or indirectly, in the ordinary course of conducting its business.

Changes in market-based factors and investor strategies may adversely affect the trading price of the Common Shares and/or the Corporation’s stock exchange listings.

The market price of the Common Shares is primarily a function of the value of the properties owned by the Corporation, as well as the ability to grow or sustain production levels, cash flow and returns to shareholders, including dividends paid. The market price of the Common Shares is also sensitive to a variety of market-based factors, including, but not limited to, an increase in passive investing (through vehicles such as exchange traded funds) and options trading, high frequency trading, the inclusion or removal of the Common Shares from one or more stock market indexes or exchange traded funds, interest rates, and the comparability of the Corporation’s performance to other growth or yield-oriented exploration and production companies. Additionally, the Common Shares may, from time to time, not meet the investment criteria or characteristics of a particular institutional or other investor, including institutional investors who are not willing or able to hold securities of oil and gas companies for reasons unrelated to financial or operational performance. Any changes in market-based factors or investor strategies, including ESG, or responsible investing criteria/rankings (for example, ESG, social impact or environmental scores), the implementation of new financial market regulations and fossil fuel divestment initiatives undertaken by governments, pension funds and/or other institutional investors, may adversely affect the trading price of the Common Shares, and/or their inclusion in the portfolios of investment managers. In addition, should the trading price of the Common Shares fall below stock exchange listing thresholds, the exchanges will review the appropriateness of the Common Shares for continued listing on such exchanges.

Changes in laws or free trade agreements, including those affecting tax, royalties and other financial and trade matters, and interpretations of those laws and trade agreements, may adversely affect the Corporation and its securityholders.

Tax laws, including those that may affect the taxation of the Corporation, or other laws or government incentive programs relating to the oil and gas industry generally, may be changed, or interpreted in a manner that adversely affects the Corporation and its securityholders. Canadian, U.S. and foreign tax authorities having jurisdiction over the Corporation (whether as a result of the Corporation's operations or its financing structures), may change or interpret applicable tax laws, treaties or administrative positions in a manner which is detrimental to the Corporation or its securityholders. Tax authorities may disagree with how the Corporation calculates its income for tax purposes. The Corporation may be subject to additional taxation (direct or indirect, including carbon tax, goods and services tax, or sales tax), levies or royalty payments imposed by government and tribal authorities with jurisdiction over its properties. The Corporation has income and other 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. In addition, the USMCA came into force on July 1, 2020, which negotiated certain changes to NAFTA that impacts merchandise commerce activities after it came into effect. This could lead to the imposition of additional duties and tariffs, or other changes that could negatively impact the Corporation’s business.

Lower oil and gas prices and higher costs increase the risk of write-downs of the Corporation's oil and gas properties, deferred tax assets and goodwill.

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 quarter and annual fiscal periods. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

The Corporation incurred non-cash asset impairments in 2020 of $994.8 million (Canadian cost centre: $134.3 million, U.S. cost centre $860.5 million) on its crude oil and natural gas assets. There were no crude oil and natural gas assets impairments recorded in 2019 and 2018. The Corporation also recorded a goodwill impairment of $202.8 million in 2020 related to the U.S. reporting unit. In 2019 a goodwill impairment of $451.1 million was recorded related to the Canadian reporting unit. At December 31, 2020, there was no goodwill remaining on the Corporation’s consolidated balance sheet.

Under U.S. GAAP, the net deferred tax assets of a corporation are limited to the estimate of future taxable income resulting from existing properties. The Corporation estimates future taxable income based on before-tax future net revenue from proved plus probable reserves, undiscounted, using forecast prices, and adjusted for other significant items affecting taxable

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income. The amount by which the gross deferred tax assets exceed the estimate of future taxable income will be charged to net income. A previously recorded valuation allowance can be reversed if the estimate of future taxable income increases.

When commodity prices are low or declining, there remains a risk for additional write-downs under U.S. GAAP. There is also risk for future impairment when the fair value of acquired assets is significantly higher than the calculated value of the assets using 12-month trailing commodity prices, as required for under U.S. GAAP. While these write-downs would not affect cash flow, the charge to earnings may be viewed unfavourably in the market. Additional write-downs may lead to the Corporation breaching its covenants under the Credit Facilities and Term Facility (when in place), and the Corporation may not be able to negotiate any covenant relief. See "Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief.”

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 is highly dependent on its success in developing and exploiting its reserves and resources 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.

Delays in payment for business operations, including the risk of default by counterparties to contracts, could adversely affect the Corporation.

In addition to the potential 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 or any counterparties to contracts (including the Corporation’s risk management, marketing, purchase and sale agreements, supplier and service contract counterparties) may also be delayed, or result in default due to, among other things:

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substantial or extended declines in oil, NGLs and natural gas prices

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

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accounting delays or adjustments for prior periods

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shortages of, or delays in, obtaining qualified personnel or equipment, including drilling rigs and completions services

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delays in the sale or delivery of products, or delays in the connection of wells to a gathering system

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adverse weather conditions, such as freezing temperatures, storms, flooding and premature thawing

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blow-outs or other accidents

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title defects

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recovery by the operator of expenses incurred in the operation of the properties, or the establishment by the operator of reserve funds 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. Any of these delays could also expose the Corporation to additional third-party credit risks.

The Corporation's information assets and critical infrastructure may be subject to cyber security risks.

The Corporation is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation's information technology systems by third parties or insiders. Although the Corporation has security measures and controls 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 reputation, breach of privacy laws, and/or disruption to 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. See also – “The increased acceptance of, or reliance on new technology may lead to financial losses or reputational issues.”

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The Corporation may be unable to compete successfully with other organizations in the oil and natural gas industry, or obtain required vendor services to compete.

The oil and natural gas industry is highly competitive. The Corporation competes for capital, acquisitions of reserves and/or resources, undeveloped lands, skilled/qualified labour, access to drilling rigs, service rigs and other equipment and materials such as sand and other proppant, hydraulic fracturing pumping equipment and related skilled personnel, access to processing facilities, pipeline and refining capacity, as well as many other services, 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 opportunities and more diverse resources to draw upon. Also, organizations that have complementary activities or are integrated may have access to, or be able to access, services or vendors that the Corporation is not able to access, thereby limiting its ability to compete.

Service providers are also in a highly competitive environment. Should low commodity prices prevail, some may choose or be required to streamline or discontinue their business, further reducing the supply of vendors and potentially increasing the competition for service, and thereby the costs to producers.

In addition, the Corporation may be at a competitive disadvantage to other industry participants able to minimize taxes under more favourable tax jurisdictions and/or regulatory environments, or which have access to a lower cost of capital.

Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief.

Declines or continued volatility in crude oil and natural gas prices may result in a significant reduction in earnings or cash flow, which could lead the Corporation to increase amounts drawn under the Bank Credit Facility in order to carry out its operations and fulfill its obligations. Significant reductions to cash flow, significant increases in drawn amounts under the Bank Credit Facility, or significant reductions to proved reserves may result in the Corporation breaching its debt covenants under the Credit Facilities and Term Facility (when in place). If a breach occurs, there is a risk that the Corporation may not be able to negotiate covenant relief with one or more of its lenders under the Credit Facilities or Term Facility. Failure to comply with debt covenants, or negotiate relief, may result in the Corporation’s indebtedness under the Credit Facilities or Term Facility becoming immediately due and payable, which may have a material adverse effect on the Corporation’s operations and financial condition.

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

Although the Corporation believes that its existing Credit Facilities and Term Facility (when in place) 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 and Term Facility may not be sufficient for future operations, or the Corporation may not be able to renew its Bank Credit Facility or Term Facility or obtain additional financing on attractive economic terms, if at all. The Term Facility, when implemented, will mature in early 2024 (three years post-closing date of the Bruin Acquisition). The Bank Credit Facility is generally available on a four-year term, extendable each year with a bullet payment required at the end of four years if the facility is not renewed. The Corporation renewed its Bank Credit Facility in 2019 and it currently expires on October 31, 2023. There can be no assurance that such a renewal will be available on favourable terms or that all the current lenders under the facility will participate or 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 by the Corporation to obtain replacement financing or financing on favourable terms, may have a material adverse effect on the Corporation's business and operations. In addition, dividends to shareholders may be eliminated, as repayment of debt under the Credit Facilities and Term Facility has priority over dividend payments by the Corporation to its shareholders.

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, 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 and cyber-attacks. The foregoing hazards could result in personal injury, loss of life, reduced production volumes or environmental and other damage to the Corporation's property

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and the property of others. The Corporation cannot fully protect against all these risks, nor are all these risks insurable. The Corporation may become liable for damages arising from 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, damage, or pay liabilities would adversely affect the Corporation's financial position, including the amount of funds that may be available for development programs, debt repayments, or dividend payments to shareholders.

The Corporation's portfolio of investment projects may expose it to increased operational and financial risks.

The Corporation's unconventional oil and gas operations (such as the development of and production from shale formations) involve certain additional risks and uncertainties. The drilling and completion of wells and operations on these unconventional assets 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. To reduce costs, wells may be drilled as part of a multi-well pad which may increase the risk of being unable to drill and complete any of the wells on the pad if problems occur. In addition, because of the depth and length of these unconventional wells, they also may be more susceptible to mechanical problems associated with drilling and completion, 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. In addition, 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 is more uncertain.

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. In addition, the Corporation's activities could expand beyond oil and natural gas production and development, and the Corporation could acquire other energy related assets. Expansion of the Corporation's activities into new business 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 Corporation's actual reserves and resources will vary from its reserves and resources 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 and Bruin’s properties will vary from the estimates summarized in this Annual Information Form and the Bruin Material Change Report, respectively, 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 reserves or resources quantities and revenues attributable thereto based on the same data. The reserves and resources 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 others described in this Annual Information Form:

●

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

●

future commodity prices, production and development costs, royalties and planned capital expenditures

●

initial production rates and production decline rates

●

ultimate recovery of reserves and resources and the success of future exploitation activities

●

marketability of production

●

the effects of government regulation and other government royalties or levies, such as environmental costs, that may be imposed over the producing life of reserves and resources

Reserves and resources 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

ENERPLUS 2020 ANNUAL INFORMATION FORM 55

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.

Reserves and resources 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. With commodity prices remaining volatile, there is a risk for write-downs under U.S. GAAP. See “Risk Factors – Lower oil and gas prices and higher costs increase the risk of write-downs of the Corporation’s oil and gas properties, deferred tax assets and goodwill”. Write-downs may lead to the Corporation breaching its covenants under the Credit Facilities and Term Facility, and the Corporation may not be able to negotiate any covenant relief. See "Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief.”

The Corporation may not realize the anticipated benefits of its acquisitions, divestments, or other corporate transactions.

From time to time, the Corporation may acquire additional oil and natural gas properties and related assets, or may acquire other corporate entities, for example, like the Bruin Acquisition. 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/or integrating the acquired assets, properties and business into the Corporation's business. 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 current or 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, assets or business 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 assets, properties or business that it acquires.

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 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 those that are higher risk/higher growth assets and the development of those acquired assets, may require more capital than anticipated 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.

The Corporation may also from time to time seek to divest of properties and assets. These divestments may consist of non-core properties or assets, or may consist of assets or properties that are being monetized to fund debt repayment, alternative projects, or development by the Corporation. There can be no assurance that the Corporation will be successful in such divestments, or realize the amount of desired proceeds from such divestments, or that such divestments will be viewed positively by the financial markets, and such divestments may negatively affect the Corporation's results of operations or the trading price of the Common Shares. In addition, although divestments typically transfer future obligations to the buyer, the Corporation may not be exempt from certain obligations in the future, including for example, abandonment and reclamation obligations, which may have an adverse effect on the Corporation’s operations and financial condition.

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The Corporation may also from time to time undertake other corporate actions or transactions which the directors and management of the Corporation believe are in the best interests of the Corporation. Any of the acquisitions, dispositions or other corporate actions may 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 the process. Although certain substantial acquisitions, business combinations or other corporate transactions, such as a potential re-domicile of the Corporation to another jurisdiction or a share consolidation, for example, could also be subject to approval by a certain majority of the Corporation’s shareholders, the Corporation may not achieve the intended or anticipated favourable results of such actions and may result in adverse consequences to certain or all of the Corporation’s stakeholders, including its shareholders.

See "Risk Factors – Risks Related to the Bruin Acquisition" below.

Risks Related to the Bruin Acquisition

THE CORPORATION MAY FAIL TO CLOSE THE BRUIN ACQUISITION OR THE CLOSING OF THE BRUIN ACQUISITION MAY BE DELAYED

The closing of the Bruin Acquisition is subject to satisfaction of certain closing conditions. The Purchase Agreement contains a covenant in favour of Enerplus USA that allows Enerplus USA to conduct due diligence prior to the closing date of the Bruin Acquisition, including an on-site visual inspection of Bruin's properties and a ASTM Phase I environmental review thereof. This due diligence may uncover liabilities that result in an adjustment to the Purchase Price, and, if the amount of title and environmental defects (subject to a minimum threshold and aggregate deductible) and casualty losses resulting in a downward adjustment to the Purchase Price are in excess of 10% of the Purchase Price, then either Enerplus USA or the Vendor may terminate the Purchase Agreement. The closing of the Bruin Acquisition will also require Enerplus to draw on the Term Facility, which has certain conditions. See "General Development of the Business – Developments in the Past Three Years" and "Description of Capital Structure – Bank Credit Facility and Term Facility" as well as the Bruin Material Change Report for additional details of the conditions and the Term Facility. There is no certainty, nor can the Corporation provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied. If the Bruin Acquisition is not completed as contemplated, the Corporation could suffer adverse consequences, including the loss of investor confidence.

THERE MAY BE UNEXPECTED COSTS OR LIABILITIES RELATED TO THE BRUIN ACQUISITION

Acquisitions of oil and natural companies are based, in large part, on engineering, environmental and economic assessments made by the acquiror, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond Enerplus' control. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated.

In connection with the Bruin Acquisition, there may be liabilities that the Corporation failed to discover or was unable to quantify in the Corporation's due diligence which the Corporation will conduct up to the closing date of the Bruin Acquisition and the Corporation may not be indemnified for some or all of these liabilities. The discovery or quantification of any material liabilities could have a material adverse effect on the Corporation's business, financial condition or future prospects. In addition, the Purchase Agreement limits the amount for which the Corporation is indemnified, such that liabilities in respect of the Bruin Acquisition may be greater than the amounts for which the Corporation is indemnified under the Purchase Agreement. See "General Development of the Business – Developments in the Past Three Years" and the Bruin Material Change Report.

THE CORPORATION MAY FAIL TO REALIZE ON THE BENEFITS OF BRUIN ACQUISITION

The Corporation believes that the Bruin Acquisition will provide a number of benefits for Enerplus. However, there is a risk that some or all of the expected benefits of the Bruin Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods the Corporation anticipates. The realization of such benefits may be affected by a number of factors, many of which are beyond the Corporation's control.

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THE CORPORATION'S LEVEL OF DEBT WILL INCREASE AS A RESULT OF THE BRUIN ACQUISITION

The Corporation's indebtedness will increase as a result of the Bruin Acquisition. If the Bruin Acquisition is completed on the terms contemplated in the Purchase Agreement, the Corporation will borrow US$400 million through a draw down under the Term Facility. Such borrowings will represent a significant increase in Enerplus' indebtedness. Such additional indebtedness will increase the Corporation's interest expense and debt service obligations and may have a negative effect on its results of operations.

As at December 31, 2020, the Corporation had US$385.4 million in principal amount of Senior Unsecured Notes outstanding. As at December 31, 2020, the Corporation's total indebtedness would have been approximately US$785.4 million after giving effect to the Bruin Acquisition, the Term Facility and the Equity Financing and the proceeds therefrom. To the extent the final purchase price for the Bruin Acquisition is higher than anticipated as a result of price adjustments, the additional amounts required to complete the Bruin Acquisition will be funded by cash on hand or borrowings under the Bank Credit Facility which would further increase the Corporation's level of outstanding indebtedness.

The Corporation's ability to service its increased debt will depend upon, among other things, Enerplus' future financial and operating performance, which will be affected by prevailing economic conditions, interest rate fluctuations and financial, business, regulatory and other factors, some of which are beyond its control. If the Corporation's operating results are not sufficient to service its current or future indebtedness, Enerplus may be forced to take actions, such as reducing dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing its debt, or seeking additional equity capital.

The Corporation could lose its status as a "foreign private issuer" in the United States, which may result in additional compliance costs and restricted access to capital markets.

The Corporation is required to assess its "foreign private issuer" (“FPI”) status under U.S. securities laws on an annual basis at the end of its second quarter. While the Corporation currently qualifies as an FPI, it could lose its FPI status in the future. If the Corporation were to lose its status as an FPI it would be required to fully comply with both U.S. and Canadian securities and accounting requirements applicable to domestic issuers in each country. In addition, if the Corporation loses its FPI, it would be required to report as a U.S. domestic issuer and be subject to other U.S. securities laws applicable to U.S. domestic issuers. The regulatory and compliance costs to the Corporation under U.S. securities laws as a U.S. domestic issuer may be significantly greater than the costs the Corporation incurs as a foreign private issuer. For example, as a U.S. domestic issuer, the Corporation would be required to file periodic reports and registration statements with the SEC on U.S. domestic issuer forms, which are more detailed and extensive in certain respects than the forms available to the Corporation as a foreign private issuer. The Corporation would also be required to report its oil and gas reserves and production information in accordance with applicable U.S. disclosure requirements. Such conversion and modifications would involve additional costs and may restrict the Corporation’s access to capital markets for a period of time until it has satisfied SEC reporting requirements. In addition, the Corporation may lose its ability to rely upon exemptions from certain corporate governance requirements on U.S. stock exchanges that are available to FPIs, which could also increase its costs.

The Corporation's risk management activities, as well as ongoing regulatory changes affecting financial institutions, 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, interest rate and foreign exchange exposure, it may forego the benefits it would otherwise experience. In addition, the Corporation's commodity price, interest rate and foreign exchange hedging activities, as well as changing bank regulations that may limit liquidity in the commodity markets, 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 entered and may in the future enter 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.

Increasing attention to ESG matters may impact our business.

Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. These standards are evolving, and if we fail to comply with these standards or are perceived to have not responded appropriately to these standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business, financial condition, and/or stock price could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for hydrocarbon products, reduced

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profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for hydrocarbon products and additional governmental investigations and private litigation against us.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our stock from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of our operations by certain investors.

The Corporation sets out to hire competent personnel and the loss of such personnel, including the Corporation's management or key personnel, could impact its business.

The Corporation’s business and prospects for future success, including the successful implementation of strategies and/or handling of issues integral to its future success, depend to a significant extent upon the continued service and performance of the management team and key personnel. Shareholders are entirely dependent on the management and key personnel 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, including hiring competent personnel. The loss of any member of Enerplus’ management team or other key personnel, and its inability to attract, motivate and retain substitute key personnel with comparable experience and skills, could materially and adversely affect the business, financial condition and results of operations.

The increased acceptance of, or reliance on new technology may lead to financial losses or reputational issues.

Technologies are often employed to assist, augment, automate or provide autonomous intelligence, which results in reduced reliance on human intervention and/or decision-making. Information technology (“IT”) and cyber risks, including cyberattacks, data breaches, cyber extortion and similar compromises, are significant risks due to the Corporation’s reliance on the internet to conduct day-to-day business activities, its technological infrastructure, and its use of third-party service providers. Additionally, use of personal devices by employees, vendors or other third parties can create further avenues for potential cyber-related incidents, as the Corporation has limited control over the use and safety of these devices. IT and cyber risks have increased during the COVID-19 pandemic, as increased malicious activities are creating more threats for cyberattacks, including COVID-19 phishing emails, malware-embedded mobile apps that purport to track infection rates, and targeting of vulnerabilities in remote access platforms as many companies continue to operate with work from home arrangements. Furthermore, the adoption of emerging technologies, such as cloud computing, artificial intelligence and robotics, call for continued focus and investment to manage risks effectively. Not managing the risks may result in business interruptions, service disruptions, financial loss, theft of intellectual property and confidential information, litigation, enhanced regulatory attention and penalties, as well as reputational damage which would have an adverse effect and, therefore, may increase the Corporation’s risk of financial or reputational loss and any damages sustained may not be adequately covered by the Corporation's current insurance coverage, or at all. See also — “The Corporation's information assets and critical infrastructure may be subject to cyber security risks.”

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. Should there be a material increase in the value of the Canadian dollar relative to the U.S. dollar, it 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. The Corporation’s business and operations in Canada and the United States have contracts that are linked to the U.S. dollar and, therefore, the Corporation is exposed to foreign currency risk on both revenues and costs. In addition, the Corporation’s Bank Credit Facility and Term Facility are U.S. dollar obligations and its Senior Unsecured Notes are U.S.-dollar denominated, therefore it is exposed to increased foreign currency risk should the Canadian dollar weaken against the U.S. dollar. The Corporation may from time to time use derivative instruments to manage a portion of its foreign exchange risk, as described in Note 14(c) to the Corporation's Financial Statements.

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Court rulings on the liability surrounding abandonment and reclamation obligations of oil and gas companies may adversely affect the Corporation.

In the U.S., oversight of reclamation and remediation activities, including those that relate to orphan wells, is administered through the respective state oil and gas agencies. The levies in the U.S. are based on production and operators are required to maintain reclamation bonds for the wells and/or fields in which they operate.

Generally, the current oil and gas asset abandonment, reclamation and remediation ("A&R") liability regime in Alberta limits each party's liability to its proportionate ownership of an asset. In the case where one joint owner of an oil and gas asset becomes insolvent and is unable to fund the required A&R activities associated with such asset, the solvent counterparties can recover the insolvent party's share of the remediation costs from the Orphan Well Association (the "OWA"). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including the Corporation, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. British Columbia has similar liability management regimes.

As a result of the Supreme Court of Canada's January 2019 decision in the case of Redwater Energy Corporation ("Redwater"), a trustee in bankruptcy is not permitted to renounce uneconomic oil and gas assets and leave these assets to be remediated by the OWA, thereby avoiding the environmental liabilities of the estate it is administering. Accordingly, the AER may now use Alberta’s provincial legislative scheme to prevent the repudiation or renunciation of an insolvent company's assets by a trustee and require the trustee to satisfy certain environmental obligations in priority to the claims of secured and unsecured creditors.

In response to lower court decisions relating to Redwater, the AER released Bulletin 2016-16 which, among other things, implemented important changes to the AER's procedures relating to liability management ratings, licence eligibility and licence transfers. In addition, changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals. Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an "unreasonable risk" such that it should not be eligible to hold AER licences.

The British Columbia provincial government has announced similar policies. The BCOGC is also exploring the development of a comprehensive liability management strategy driven in part by the proliferation of orphan sites. The imposition of timelines for cleanup of inactive sites is among the measures under consideration.

These changes may impact the Corporation's ability to transfer its licences, approvals or permits in the course of a divestment, and may result in increased costs and delays or require changes to or abandonment of projects and transactions. As a result of the decision in Redwater, lenders may reduce the availability of credit to oil and gas issuers that utilize secured loans, thereby negatively affecting the financial capacity of such issuers, including potential partners and counterparties of the Corporation. Lenders also may generally increase their scrutiny of oil and gas assets held by producers, including the Corporation, and the associated A&R liabilities in determining whether to provide credit, may require borrowers to adhere to more stringent A&R-related operational covenants, and may increase the cost of providing credit.

The Supreme Court decision in Redwater also could make the transfer of oil and gas assets from insolvent parties more challenging if a trustee in bankruptcy is unable to separate economic assets from uneconomic assets within the insolvent party's estate in order to facilitate a sale process. The result could be additional liabilities being placed upon the OWA. The OWA may seek funding for such liabilities from industry participants, including the Corporation, through an increase in its annual levy, further changes to regulations, or other means. While the impact on the Corporation of any legislative, regulatory or policy decisions as a result of the Redwater decision cannot be reliably or accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact the Corporation and materially and adversely affect, among other things, the Corporation’s business, financial condition, results of operations and cash flow.

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 contractual, trust-related or offset obligations which they may default in satisfying and which may adversely affect the validity of an oil and gas lease in which the Corporation has an

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interest. The existence of title defects, unsatisfied contractual, trust-related or 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.

Dividends and other payments on the Corporation's Common Shares are variable.

Although the Corporation currently intends to continue to return cash to shareholders with a monthly cash dividend payment and/or share repurchases, investor returns may change from time to time due to changes in the amount of the cash dividend paid or shares repurchased. Cash dividends are declared in Canadian dollars and are converted to foreign denominated currencies at the spot exchange rate at the time of payment. Consequently, 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 may be reduced when converted to shareholders’ home currency. In addition, shareholders may be subject to withholding taxes in accordance with tax treaties or domestic tax law changes, as determined by shareholder residency.

The amount of cash available to the Corporation to pay dividends or repurchase shares can vary significantly from period to period for many reasons including, among other things:

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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)

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fluctuations in the costs to produce oil, NGLs and natural gas, including royalty burdens, and costs to administer and manage the Corporation and its subsidiaries

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the amount of cash required or retained for debt service or repayment

●

amounts required to fund capital expenditures and working capital requirements

●

access to equity markets

●

foreign currency exchange rates and interest rates

●

the risk factors set forth in this Annual Information Form

The decision whether to pay dividends and the amount of any such dividend is subject to the discretion of the board of directors of the Corporation, which regularly evaluates the Corporation's dividend policy, and the 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.

In addition, to the extent the Corporation uses internally-generated cash flow to repurchase shares, or 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 may 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 or repurchase shares from 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.

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 other companies involved in the oil and gas industry which are in competition to the interests of the Corporation. Directors are required to abstain from voting on matters when they are in conflict. Employees, including officers, are not permitted to partake in activities that do not support the best interests of Enerplus. Where employee conflicts exist, they are to be provided in writing to the People & Culture Department, which discloses all conflicts to General Counsel. See "Directors and Officers – Conflicts of Interest" and Enerplus’ Code of Business Conduct at www.enerplus.com.

ENERPLUS 2020 ANNUAL INFORMATION FORM 61

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 reserves engineers) are residents of Canada, and a 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 by U.S. courts for liability based solely upon the U.S. federal securities laws or the securities laws of any state within the United States.

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 and the NYSE for 2020.


	TSX Trading			NYSE Trading
Month	High ($)	Low ($)	Volume	High (US$)	Low (US$)	Volume
January	9.55	6.50	32,713,182	7.35	4.92	11,085,043
February	7.23	5.38	26,554,314	5.46	4.02	13,810,573
March	5.92	1.62	67,080,890	4.44	1.15	16,948,764
April	3.77	1.95	42,074,715	2.75	1.39	9,624,897
May	4.12	3.02	34,577,828	2.97	2.15	5,605,807
June	4.99	3.44	30,818,351	3.72	2.50	8,652,458
July	4.03	3.01	27,718,986	2.96	2.22	8,387,916
August	4.24	3.33	19,188,776	3.19	2.43	5,697,967
September	3.58	2.31	27,833,747	2.74	1.72	10,645,551
October	2.78	2.28	23,657,484	2.13	1.71	10,448,513
November	3.69	2.22	32,789,693	2.82	1.70	11,365,493
December	4.47	3.20	28,352,251	3.50	2.49	10,502,016

62 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 and principal occupation for the past five years for each current director of the Corporation are set forth below.


Name and Residence	Director Since	Principal Occupation for Past Five Years

Hilary A. Foulkes⁽¹⁾⁽⁷⁾ Calgary, Alberta, Canada	February 2014	Corporate director and Senior Advisor to Tudor Pickering Holt & Co. Canada.

Judith D. Buie^(2)(3)(5)Houston, Texas, United States	January 2020	Corporate director and oil and gas industry advisor. Prior thereto, Ms. Buie was Co-President and Senior Vice President Engineering for RPM Energy Management LLC from 2012-2017.

Karen E. Clarke-Whistler^(2)(4)(6)Toronto, Ontario, Canada	December 2018	Corporate director and consultant providing ESG advisory services. Prior thereto, Chief Environment Officer at TD Bank Group until her retirement in 2018.

Ian C. Dundas Calgary, Alberta, Canada	July 2013	President & Chief Executive Officer of Enerplus.


Robert B. Hodgins^(2)(3)(4)(8) Calgary, Alberta, Canada	November 2007	Mr. Hodgins is a Senior Advisor, Investment Banking at Canaccord Genuity Corp. since September 2018 and has been an independent businessman since November 2004.

Susan M. MacKenzie^(3)(4)(6) Calgary, Alberta, Canada	July 2011	Corporate director. Prior thereto, independent consultant from 2010 to 2015.

Elliott Pew Boerne, Texas, United States	September 2010	Corporate director.

Jeffrey W. Sheets^(2)(5)(6) Houston, Texas, United States	December 2017	Corporate director. Prior thereto, Executive Vice President and Chief Financial Officer of ConocoPhillips Company from October 2010 to February 2016.

Sheldon B. Steeves^(3)(5)(6) Calgary, Alberta, Canada	June 2012	Corporate director.

Notes:

(1)	Chair 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 Chair, Judith D. Buie, Karen E. Clarke-Whistler and Jeffrey W. Sheets.

(3)	The Corporate Governance & Nominating Committee is currently comprised of Susan M. MacKenzie as Chair, Judith D. Buie, Robert B. Hodgins and Sheldon B. Steeves.

(4)	The Compensation & Human Resources Committee is currently comprised of Susan M. MacKenzie as Chair, Robert B. Hodgins and Karen E. Clarke-Whistler.

(5)	The Reserves Committee is currently comprised of Sheldon B. Steeves as Chair, Judith D. Buie and Jeffrey W. Sheets.

(6)	The Safety & Social Responsibility Committee is currently comprised of Jeffrey W. Sheets as Chair, Karen E. Clarke-Whistler, Susan M. MacKenzie and Sheldon B. Steeves.

(7)

Ms. Foulkes was a director of Parallel Energy Trust (“Parallel”). On November 9, 2015, Parallel and its affiliated entities filed an application for protection under the CCAA and voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court of Delaware. Ms. Foulkes ceased to be a director of Parallel on March 1, 2016. Parallel filed an assignment in bankruptcy and proceedings under the CCAA were terminated in March 2016.

(8)

Mr. Hodgins was a director of Skope Energy Inc. (“Skope”) from December 15, 2010 to February 19, 2013. On November 27, 2012, Skope was granted protection from its creditors by the Court of Queen’s Bench of Alberta pursuant to the CCAA to implement a restructuring which was approved by the required majority of Skope’s creditors. The restructuring was sanctioned by the Court of Queen’s Bench of Alberta in February 2013.

ENERPLUS 2020 ANNUAL INFORMATION FORM 63

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.

Jodine J. Jenson Labrie Calgary, Alberta, Canada	Senior Vice-President & Chief Financial Officer	Senior Vice-President & Chief Financial Officer of the Corporation since September 2015. Prior thereto, Vice-President, Finance of the Corporation.

Wade D. Hutchings Denver, Colorado, United States	Senior Vice-President, Chief Operating Officer	Senior Vice-President & Chief Operating Officer of the Corporation since February 11, 2020. Prior thereto, Senior-Vice President, Exploration & Production at Devon Energy Corporation from 2017 to 2019. Prior thereto, President, Alaska and Regional Vice-President, Mid-Continent at Marathon Oil.

Garth R. Doll Calgary, Alberta, Canada	Vice-President, Marketing	Vice-President, Marketing of the Corporation since February 2019. Prior thereto, Manager, Marketing of the Corporation.

Terry S. Eichinger Calgary, Alberta, Canada	Vice-President, Drilling, Completions & Operations Support	Vice-President, Drilling, Completions & Operations Support since June 2020. Prior thereto, Vice-President, U.S. Operations & Engineering of the Corporation since September 2018. Prior thereto, Senior Manager, U.S. Operations & Engineering of the Corporation.

Nathan D. Fisher Denver, Colorado, United States	Vice-President, United States Business Unit	Vice-President, United States Business Unit since June 2020. Prior thereto, Vice-President, U.S. Development & Geosciences of the Corporation since September 2015. Prior thereto, Manager, Geology & Geophysics for U.S. Operations of the Corporation.

Daniel J. Fitzgerald Calgary, Alberta, Canada	Vice-President, Business Development	Vice-President, Business Development of the Corporation since September 2015. Prior thereto, Manager, Business Development & Strategic Planning of the Corporation.

John E. Hoffman Calgary, Alberta, Canada	Vice-President, Canadian Assets & Corporate Sustainability	Vice-President, Canadian Assets & Corporate Sustainability of the Corporation since June 2020. Prior thereto, Vice-President, Canadian Operations since April 2015. Prior thereto, General Manager, North America Onshore at Suncor Energy Inc.

David A. McCoy Calgary, Alberta, Canada	Vice-President, General Counsel & Corporate Secretary	Vice-President, General Counsel & Corporate Secretary of the Corporation.

Shaina B. Morihira Calgary, Alberta, Canada	Vice-President, Finance	Vice-President, Finance of the Corporation since February 2018. Prior thereto, Corporate Controller of the Corporation since July 2015. Prior thereto, Controller, Financial of Progress Energy Canada Ltd.

COMMON SHARE OWNERSHIP

As of February 17, 2021, the directors and officers of the Corporation named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 959,985 Common Shares, representing approximately 0.4% of the outstanding Common Shares as of that date.

64 ENERPLUS 2020 ANNUAL INFORMATION FORM

CONFLICTS OF INTEREST

Certain of the directors and officers named above may be directors or officers of issuers or other companies which are in competition with the Corporation, and as such may encounter conflicts of interest 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 operations or liquidity. Notwithstanding the above, the Corporation is aware of a class action filed in Fort Berthold Tribal Court in November 2017 as Civil Action No. 2017-0505 against the Corporation and fifteen other companies operating on the FBIR (the “Action”). The plaintiffs in the Action are members of the Three Affiliated Tribes who own mineral interests on the FBIR and allege that the defendant companies have committed trespass, failed to pay royalties properly, etc. They seek judgement against the defendant group for $585 million in damages, $500 million in punitive damages, and disgorgement of the value of oil and gas produced from the plaintiffs’ property. The Corporation believes the claim, as against the Corporation, is without merit.

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, 2018 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 in the normal course of business and relating to the Credit Facilities 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; if they were filed prior to the Conversion, they are under the Fund's SEDAR profile at www.sedar.com and on Form 6-K on the Fund's EDGAR profile at www.sec.gov:

Amended and Restated Bank Credit Facility (November 5, 2012); the First Amending Agreement relating thereto (January 13, 2014); the Second Amending Agreement relating thereto (May 13, 2014); the Third Amending Agreement relating thereto (SEDAR – December 1, 2014; EDGAR – December 9, 2014); the Fourth Amending Agreement relating thereto (November 6, 2015); the Fifth Amending Agreement relating thereto (November 7, 2016); the Sixth Amending Agreement relating thereto (November 8, 2018); and the Seventh Amending Agreement relating thereto (November 7, 2019);

ENERPLUS 2020 ANNUAL INFORMATION FORM 65

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

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

4.	Form of the Note Purchase Agreement for the Senior Unsecured Notes issued in 2014 (SEDAR – October 10, 2014; EDGAR – October 15, 2014).

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.

1.	the Articles of Amalgamation (January 2, 2013), and

2.	By-law No. 1 of the Corporation (June 16, 2014); and By-law No. 2 of the Corporation (May 6, 2016).

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 internal estimates of contingent resources attributable to the Corporation's interests in the Fort Berthold, North Dakota area, which are referred to in this Annual Information Form in Appendix A. 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, no outstanding Common Shares. NSAI prepared the NSAI Report in respect of the reserves and contingent resources attributable to the Corporation's interests in the Marcellus property, a summary of which is contained in this Annual Information Form. As of the date of the NSAI Report, the designated professionals of NSAI, as a group, beneficially owned, directly or indirectly, no outstanding Common Shares.

KPMG LLP (“KPMG”) was appointed as the auditors of the Corporation on May 31, 2017 and have confirmed with respect to the Corporation, that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations, and also that they are independent accountants with respect to the Corporation under all relevant U.S. professional and regulatory standards.

Transfer Agent and Registrar

The transfer agent and registrar for the Common Shares in Canada is AST Trust Company (Canada), at its principal offices in Calgary, Alberta and Toronto, Ontario. American Stock Transfer & Trust Company, LLC at its principal offices in Brooklyn, New York 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 2021 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. Shareholders who wish to receive printed copies of these documents free of charge should contact the Corporation's Investor Relations Department using the contact information on the back cover of this Annual Information Form.

66 ENERPLUS 2020 ANNUAL INFORMATION FORM

APPENDIX A

Appendix A – Contingent Resources Information

NOTE TO READER REGARDING DISCLOSURE OF CONTINGENT RESOURCES INFORMATION

All of the Corporation's contingent resources have been evaluated in accordance with NI 51-101. NSAI, an independent petroleum consulting firm based in Dallas, Texas, has evaluated the Corporation's contingent resources attributable to its Marcellus properties located in Pennsylvania, United States, using the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021. The Corporation has evaluated the contingent resources associated with properties located in North Dakota, United States. This evaluation uses similar evaluation parameters, including the same forecast price, inflation and exchange rate assumptions utilized by McDaniel, which as required by NI 51-101 has audited the Corporation's internal evaluation.

No resources information in this Appendix A, give effect to the Bruin Acquisition or any of Bruin's assets, production, reserves or other operational information. For additional information regarding the Bruin Acquisition, see the Bruin Material Change Report.

The following sections and tables summarize, as at December 31, 2020, the Corporation's "best estimate" (as defined below) contingent resources, including risked contingent resource volumes and risked net present value of future net revenue of contingent resources in development pending project maturity sub-class, together with certain information, estimates and assumptions associated with such 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.

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 before deducting income taxes. For additional information, see "Business of the Corporation – Tax Horizon", "Industry Conditions" and "Risk Factors" in the Annual Information Form.

With respect to pricing information in the following resources information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and transportation. The NGLs prices were adjusted to reflect historical average prices received.

The estimated future net revenue to be derived from the production of the contingent resources set out in this Appendix A is based on the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021, and was utilized by NSAI and by the Corporation in its internal evaluations for consistency in the Corporation's reporting, and the inflation and exchange rate assumptions set forth under "Oil and Natural Gas Reserves – Forecast Prices and Costs" in the Annual Information Form. Also see "Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Description of Price and Cost Assumptions" in the Annual Information Form.

It should not be assumed that the summary of risked net present value of estimated future cash flows shown in the tables below is representative of the fair market value of the contingent resources. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and contingent resources estimates of the Corporation's crude oil, natural gas liquids and natural gas contingent resources provided herein are estimates only. Actual resources may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained below.

Contingent Resources Categories and Levels of Certainty for Reported Resources

In this Appendix A, 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 and its Marcellus shale gas property located in Pennsylvania.

"resources" are petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced.

"contingent resources" are defined as those quantities of petroleum estimated, as of 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

A-1 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 economically recoverable based on the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021.

The economic contingent resources estimates in this Appendix A 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”.

"risked" means that the applicable volumes or revenues have been adjusted for the probability of loss or failure in accordance with the COGEH. See "Description of Properties" below.

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 reserves and resources estimates, and those variations could be material".

Contingent Resources Development Status

Contingent resources may be divided into the following project maturity sub-classes:

"development pending" resources sub-class is assigned to contingent resources for a particular project where resolution of the final conditions for development is being actively pursued (there is a high chance of development) and the project is expected to be developed in a reasonable timeframe;

"development on hold" resources sub-class is assigned to contingent resources for a particular project where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator;

"development unclarified" resources are those for which additional information is being acquired;

"development not viable" resources are those where no further data acquisition or evaluation is currently planned and there is a low chance of development.

All of the Corporation's contingent resources fall into the "development pending" sub-class.

CONTINGENT RESOURCES DATA

The following tables set forth the "best estimate" of gross and net risked contingent resources volumes and risked net present value of future net revenue attributable to the Corporation's contingent resources in the development pending project maturity sub-class, at December 31, 2020, using forecast price and cost cases. An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is no certainty that the estimate of risked net present value of future net revenue will be realized.

ENERPLUS 2020 ANNUAL INFORMATION FORM A-2

Summary of Risked Oil and Gas

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2020

CONTINGENT RESOURCES

PROJECT MATURITY SUB-CLASS

Light &
Medium Oil

Heavy Oil

Tight Oil

Natural Gas
Liquids

Conventional
Natural Gas

Shale Gas

Total

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

(Mbbls)

(MMcf)

(MBOE)

Development Pending

53,607

42,999

5,790

4,644

529,093

423,343

147,579

118,200

Risked Net Present Value of Future Net Revenue

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2020


RISKED NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)
	Before Deducting Income Taxes
PROJECT MATURITY SUB-CLASS	0%	5%	10%	15%	20%
	(in $ millions)
Development Pending	1,522.1	678.0	320.0	156.2	76.5

A-3 ENERPLUS 2020 ANNUAL INFORMATION FORM

DESCRIPTION OF PROPERTIES

Outlined below is a description of the Corporation's "best estimate" of economic contingent resources for its Canadian and U.S. crude oil and natural gas properties and assets. There is no certainty it will be commercially viable to produce, or that the Corporation will produce, any portion of the volumes currently classified as "contingent resources".

Canadian Crude Oil Properties

In 2019, the Corporation disclosed development pending contingent resources for its Giltedge, Medicine Hat Glauconitic “C” and Saskatchewan Ratcliffe properties. Due to the reduction in the average of the price forecasts of GLJ, McDaniel and Sproule used as of January 1, 2021, compared to 2019, and expected rates of return, it was determined that the chance of development was less than 80% for the contingent resources associated with these properties and the volumes could no longer be considered “development-pending” contingent resource. As such, there are no contingent resources volumes associated with the Corporation’s Canadian crude oil properties as of December 31, 2020.

U.S. Crude Oil Properties

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 an unrisked "best estimate" of 72.0 MMBOE (64.8 MMBOE risked) of economic contingent resources attributable to these formations, effective as of December 31, 2020, an increase of 60% from the estimate as of December 31, 2019. The increase compared to 2019 was the result of 1.5 MMBOE of unrisked contingent resources being converted to undeveloped reserves, which were offset by an additional 25.6 MMBOE of unrisked contingent resources due to additional locations being identified based on revised geological interpretation and minor positive revisions to previous estimates of 2.9 MMBOE unrisked contingent resources. The recovery of these tight oil contingent resources is under a primary solution gas drive through horizontal wells completed with multiple fracture treatments. These contingent resources represent approximately 136.3 net future drilling locations over and above 149.0 net booked drilling locations identified in the Corporation's booked proved plus probable reserves. The capital required to drill these locations is estimated to be US$996.1 million (or CDN$1,305.6 million) between 2026 and 2030. These estimates are based primarily upon a drilling density of up to 10 wells per drilling spacing unit in the Bakken and Three Forks formations combined. The contingent resources average expected ultimate recovery per well is estimated at 543 MBOE. These contingent resources are economic using established technologies and under current forecast commodity prices. Given the drilling density to date, these contingent resources represent a non-reserve land utilization of 100% for the operated lands. All of these contingent resources are classified into "development pending" project maturity sub-class, with an estimated chance of development of 90% as their development is expected to immediately follow the reserves development. After application of the chance of development, the risked NPV discounted at 10% is CDN$180.3 million. The Corporation has approximately 239 net reserves wells currently on production in this area.

The primary contingency which currently prevents the classification of the Corporation's disclosed contingent resources associated with the Fort Berthold, North Dakota property as reserves is the development timeline beyond what is already assigned for the Corporation’s undeveloped reserves. Significant positive factors related to the estimate include continued advancement of drilling and completion technology, and performance of producing wells that continues to exceed expectations resulting in positive revisions to reserves. Another factor related to the estimate is the limited long-term performance history in the immediate area of the contingent resources. 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 provision 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 the Annual Information Form.

U.S. Natural Gas Properties

NSAI has conducted an independent assessment of the contingent resources attributable to the Corporation's interests in the Marcellus property and has provided an unrisked "best estimate" of economic shale gas contingent resources of approximately 621.2 Bcf (496.9 Bcf risked) at December 31, 2020. The unrisked NPV (discounted at 10%) associated with these contingent resources is CDN$174.6 million (CDN$139.7 million risked). Approximately 101.5 Bcf of unrisked contingent resources were reclassified as reserves in 2020. An additional 59.2 Bcf of unrisked contingent resources (47.3 Bcf risked) was assigned in 2020 and attributed to additional locations being identified and improved performance of offset wells compared to 2019. The remaining contingent resources are economic based on the forecast price and cost assumptions used for the Corporation's year-end 2020 reserves evaluations. This estimate represents a non-reserve land utilization rate of 95% and average well ultimate recovery of approximately 19.0 Bcf. These contingent resources are classified into "development pending" project maturity sub-class as it is anticipated their development will be a continuation of the current reserves development. These contingent resources have an estimated 80% chance of

ENERPLUS 2020 ANNUAL INFORMATION FORM A-4

development. It is also estimated that US$288.0 million (or CDN$377.3 million) of capital will be required to develop these contingent resources with multifractured horizontal wells, and development will occur from 2026 to 2036.

The primary contingencies which currently prevent the classification of the Corporation's disclosed contingent resources associated with its Marcellus interests as reserves consist of limitations to development based on adverse topography or other surface restrictions, the receipt of all required regulatory permits and approvals to develop the land, and limited access to confidential information of operators’ long-term development plans that would support the recognition of reserves on the Corporation's areas of interest. Significant negative factors related to the estimate include the following: 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 property 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, funding and provision 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 the Annual Information Form.

A-5 ENERPLUS 2020 ANNUAL INFORMATION FORM

APPENDIX B‌

Appendix B – Report on Reserves Data and Contingent Resources Data by Independent Qualified Reserves Evaluator or Auditor

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

We have audited, evaluated and reviewed, as applicable, the Corporation’s reserves data and contingent resources data as at December 31, 2020. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2020, estimated using forecast prices and costs. The contingent resources data are risked estimates of volume of contingent resources and related risked net present value of future net revenue as at December 31, 2020, estimated using forecast prices and costs.

The reserves data and contingent resources data are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the reserves data and contingent resources data based on our audit, evaluation and review.

We carried out our audit, evaluation and review, as applicable, in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

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

The following table sets forth the net present value of 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 Corporation evaluated and reviewed for the year ended December 31, 2020, and identifies the respective portions thereof that we have evaluated and reviewed and reported on to the Corporation's management:

Independent

Qualified

Net Present Value of Future Net Revenue

Reserves

Effective Date of

(before income taxes, 10% discount rate)

Evaluator

Evaluation or Review

Location of

(in $ thousands)

or Auditor

Report

Reserves

Audited

Evaluated

Reviewed

Total

McDaniel & Associates Consultants Ltd.

December 31, 2020

Canada

244,567.8

41,010.8

285,578.6

McDaniel & Associates Consultants Ltd.

December 31, 2020

North Dakota, Montana & Colorado, USA

US$

1,281,863.8

⁽¹⁾

US$

1,281,863.8 ⁽¹⁾

Netherland, Sewell & Associates, Inc.

US$

483,186.5

⁽¹⁾

US$

483,186.5 ⁽¹⁾

December 31, 2020

Pennsylvania, USA

TOTALS

2,554,900.0

41,010.8

2,595,910.8

(1) Future net revenue in $US was converted to $Cdn using the average of GLJ's, McDaniel's and Sproule's January 1, 2021 forecast of exchange rates. These are 0.768 for 2021, 0.765 for 2022 and 0.763 thereafter.

The following table sets forth the risked volume and risked net present value of future net revenue of contingent resources (before deduction of income taxes) attributed to contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the Corporation’s statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources that we have audited and evaluated and reported on to the Corporation’s management:

B-1 ENERPLUS 2020 ANNUAL INFORMATION FORM

Independent

Effective

Qualified

Date of

Location of

Risked Net Present Value of Future Net Revenue

Reserves

Audit or

Resources

Risked

(before income taxes, 10% discount rate)

Evaluator

Evaluation

Other than

Volume

(in $ thousands)

Classification

or Auditor

Report

Reserves

(MMBOE)

Audited

Evaluated

Total

Development Pending Contingent Resources (2C)

McDaniel & Associates Consultants Ltd.

December 31, 2020

North Dakota, USA

64.8

$US

137,641.9

$US

137,641.9

Development Pending Contingent Resources (2C)

Netherland, Sewell & Associates, Inc.

December 31, 2020

Pennsylvania, USA

82.8

$US

106,644.6

$US

106,644.6

In our opinion, the reserves data and contingent resources data, respectively, audited and 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.

We have no responsibility to update our reports referred to in paragraphs 5 and 6 for events and circumstances occurring after the respective effective dates of our reports.

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

10.

Executed as to our report referred to above:


MCDANIEL & ASSOCIATES CONSULTANTS LTD.		NETHERLAND, SEWELL & ASSOCIATES, INC.
"signed by B. Hamm"		"signed by C. H. (Scott) Rees III"
B. Hamm, P.Eng.		C. H. (Scott) Rees III, P.E.
President & CEO		Chairman and Chief Executive Officer

Calgary, Alberta, Canada		Texas Registered Engineering Firm F-2699
		Dallas, Texas, USA

February 18, 2021		February 18, 2021

ENERPLUS 2020 ANNUAL INFORMATION FORM B-2

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") is 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 and contingent resources data.

Independent qualified reserves evaluators have evaluated, reviewed and audited, as applicable, the Corporation's reserves data and contingent resources data. The report of the independent qualified reserves evaluators is presented as Appendix 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 and contingent resources 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, contingent resources data and other oil and gas information

(b)	the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves and resources data and

(c)	the content and filing of this report

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

ENERPLUS CORPORATION

"Ian C. Dundas"		"John E. Hoffman"
Ian C. Dundas		John E. Hoffman
President & Chief Executive Officer		Vice President, Canadian Assets & Corporate Sustainability


"Hilary Foulkes"		"Sheldon B. Steeves"
Hilary Foulkes		Sheldon B. Steeves
Director		Director

February 19, 2021

C-1 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 included in this Appendix D.

B.COMPOSITION OF THE AUDIT & RISK MANAGEMENT COMMITTEE

The current members of the Committee are Robert B. Hodgins (Committee Chair), Judith D. Buie, Karen E. Clarke-Whistler, and Jeffrey W. Sheets. Each member of the Committee is independent and financially literate within the meaning of National Instrument 52-110 and the NYSE listing standards.

C.RELEVANT EDUCATION AND EXPERIENCE


Name (Director Since)		Principal Occupation and Biography

Robert B. Hodgins (Honors B.A. (Business), CPA, CA) (Director since November 2007) Other Public Directorships ● AltaGas Ltd. (energy midstream services) ● Gran Tierra Energy Inc. (international oil and gas exploration and production company) ● MEG Energy Corp. (oil sands company)	Mr. Hodgins is a Senior Advisor, Investment Banking at Canaccord Genuity Corp. since September 2018 and 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.

Judith D. Buie (B.Sc. (Chemical Engineering)) (Director since January 2020) Other Public Directorships ● Sundance Energy Inc. (oil and gas company)	Ms. Buie has spent over 30 years in the upstream oil and gas business leading business development initiatives and managing oil and gas assets through different commodity and life cycles. From 2012 to 2017, Ms. Buie was Co-President and Senior Vice President Engineering for RPM Energy Management LLC, a private company which works exclusively with KKR, a leading global investment firm, to evaluate and manage oil and gas investments. Prior to RPM, Ms. Buie held a variety of leadership and technical positions with Newfield Exploration Company from 2001 to 2011, and prior thereto she served in various technical roles at BP, Vastar Resources and ARCO. Ms. Buie received a Bachelor of Science in Chemical Engineering from Texas A&M University.

ENERPLUS 2020 ANNUAL INFORMATION FORM D-1


Name (Director Since)		Principal Occupation and Biography

Karen E. Clarke-Whistler (B. Sc. (Biology), M. Sc. (Land Resource Science)) (Director since December 2018)	Ms. Clarke-Whistler has over 30 years of experience in strategic management of environmental and social issues. In late 2018, she retired as Chief Environment Officer of TD Bank Group, a position she held for ten years. Prior to that she spent 20 years as an environmental consultant to energy, resource development and financial clients in the Americas, Europe and Africa. She began her consulting career with Beak Consultants Limited in 1985 where she progressed over a ten-year period to Senior Principal and President. She then joined Golder Associates where she was a partner in the Sustainable Development practice until 2008. She has served on a number of private and not-for-profit boards, and is currently on the board of directors of two private companies and is an advisor to Canada’s Ecofiscal Commission. Ms. Clarke-Whistler received a B.Sc. in Biology from the University of Toronto, an M.Sc. in Land Resource Science from the University of Guelph, and holds the ICD.D designation from the Institute of Corporate Directors. She has twice been recognized as one of Canada’s “Clean16” in recognition of her contribution to clean capitalism in the financial sector.

Jeffrey W. Sheets (B.Sc. (Chemical Engineering), MBA (Finance)) (Director since December 2017) Other Public Directorships ● Schlumberger Limited (global oilfield services and equipment) ● Westlake Chemical Corporation (chemicals and plastics sales and manufacturing)	Mr. Sheets served as executive vice president and chief financial officer of ConocoPhillips Company from October 2010 to February 2016. Mr. Sheets was associated with ConocoPhillips and its predecessor companies for more than 36 years and served in a variety of roles, including senior vice president of planning and strategy as well as vice president and treasurer. He began his career in 1980 as a process engineer with Phillips Petroleum Company. Mr. Sheets serves on the board of directors of Schlumberger Limited and Westlake Chemical Corporation and is a former director of DCP Midstream Partners LP. Mr. Sheets received a Bachelor’s degree in Chemical Engineering from the Missouri University of Science and Technology and an MBA from the University of Houston. Mr. Sheets is a member of the Board of Trustees at the Missouri University of Science and Technology.

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 KPMG in 2020 and 2019 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 KPMG described above is compatible with maintaining that firm's independence from the Corporation.

D-2 ENERPLUS 2020 ANNUAL INFORMATION FORM

E.EXTERNAL AUDITOR SERVICE FEES


		2020		2019
	(in $ thousands)
Audit fees⁽¹⁾	$	894.4	$	778.8

Audit-related fees⁽²⁾		-		-

Tax fees⁽³⁾		32.0		145.7

All other fees⁽⁴⁾		-		-

TOTAL	$	926.4	$	924.5

Notes:

(1)	Audit fees were for professional services rendered for the audit of the Corporation's annual financial statements and review 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 and review to identify recovery opportunities.

(4)	All other fees related to products and services other than those described as "Audit fees" and "Tax fees".

ENERPLUS 2020 ANNUAL INFORMATION FORM D-3

AUDIT & RISK MANAGEMENT COMMITTEE CHARTER

I. AUTHORITY

The Audit & Risk Management Committee (the "Committee") of the Board of Directors (the "Board") of Enerplus Corporation (the "Corporation") shall be comprised of three or more Directors as determined from time to time by resolution of the Board. Consistent with the appointment of other Board committees, the members of the Committee shall be elected by the Board at the first meeting of the Board following each annual meeting of Shareholders of the Corporation or at such other time as may be determined by the Board. The 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 communication 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 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

D-4 ENERPLUS 2020 ANNUAL INFORMATION FORM

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-approving 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) have a private meeting with the external auditors at every quarterly Committee meeting

h) obtain annually the auditors’ views on competency and integrity of the Committee and senior financial executives

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

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

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

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

8. Receipt of certifications from the CEO and CFO

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

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

ENERPLUS 2020 ANNUAL INFORMATION FORM D-5

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 and

i) management’s acknowledgement of its responsibility towards the financial statements

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

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

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

10. Establishment of the 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 US and Canadian requirements

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

16. Review annually the report of the external auditors 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 conduct the Corporation’s key risk assessment and review the policies to monitor, mitigate and report such business risks.

D-6 ENERPLUS 2020 ANNUAL INFORMATION FORM

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 Information Form, 40-F and the Information Circular regarding the 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, review the adequacy of its Charter and bring 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

24. Hold an in-camera session of the independent members of the Committee at each meeting of the Committee

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.

ENERPLUS 2020 ANNUAL INFORMATION FORM D-7

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

REPORTS

Exhibit 99.2

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2020, our internal control over financial reporting is effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2020, has been audited by KPMG LLP, the Independent Registered Public Accounting Firm, who also audited the Company’s Consolidated Financial Statements for the year ended December 31, 2020.

/s/ Ian C. Dundas

/s/ Jodine J. Jenson Labrie

President and
Chief Executive Officer

Senior Vice President and
Chief Financial Officer

Calgary, Alberta

February 18, 2021

ENERPLUS 2020 FINANCIAL SUMMARY 1

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Enerplus Corporation

Opinion on Internal Control Over Financial Reporting

We have audited Enerplus Corporation’s and its subsidiaries (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of income/(loss) and comprehensive income/(loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 18, 2021 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Chartered Professional Accountants
Calgary, Canada
February 18, 2021

2 ENERPLUS 2020 FINANCIAL SUMMARY

Management’s Responsibility for Financial Statements

In management’s opinion, the accompanying consolidated financial statements of Enerplus Corporation have been prepared within reasonable limits of materiality and in accordance with accounting principles generally accepted in the United States of America. Since a precise determination of many assets and liabilities is dependent on future events, the preparation of financial statements necessarily involves the use of estimates and approximations. These have been made using careful judgment and with all information available up to February 18, 2021. Management is responsible for all information in the annual report and for the consistency, therewith, of all other financial and operating data presented in this report.

To meet its responsibility for reliable and accurate financial statements, management has established and monitors systems of internal control which are designed to provide reasonable assurance that financial information is relevant, reliable and accurate, and that assets are safeguarded and transactions are executed in accordance with management’s authorization.

The consolidated financial statements have been examined by KPMG LLP, Independent Registered Public Accountants. Their responsibility is to express a professional opinion on the fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. The Report of Independent Registered Public Accounting Firm outlines the scope of their examination and sets forth their opinion.

The Audit Committee, consisting exclusively of independent directors, has reviewed these statements with management and the Independent Registered Public Accounting Firm and has recommended their approval to the Board of Directors. The Board of Directors has approved the consolidated financial statements of the Company.

/s/ Ian C. Dundas

/s/ Jodine J. Jenson Labrie

President and
Chief Executive Officer

Senior Vice President and
Chief Financial Officer

Calgary, Alberta

February 18, 2021

ENERPLUS 2020 FINANCIAL SUMMARY 3

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Enerplus Corporation

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Enerplus Corporation (the Company) as of December 31, 2020 and 2019, the related consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 18, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Realizability of the deferred income tax asset associated with the Company’s Canadian operation.

As discussed in Note 17 to the consolidated financial statements, as of December 31, 2020, the Company had recognized a deferred income tax asset of $607 million of which $211 million relates to the Company’s Canadian operations. The Company estimated that there is a greater than 50 percent likelihood that the deferred income tax asset will be realized. The determination of the deferred income tax asset associated with the Canadian operation involves a number of estimates, including the future cash flows associated with the estimated proved and probable oil and gas reserves of the Canadian operation (“Canadian reserves”). The estimation of the Canadian reserves requires the expertise of independent reservoir engineering specialists, who take into consideration assumptions related to its forecasted production, forecasted operating, royalty and capital cost assumptions and forecasted oil and gas prices (“reserve assumptions”). The Company engages independent reservoir engineering specialists to estimate the Canadian reserves.

We identified the evaluation of the realizability of the Canadian operation’s deferred income tax asset as a critical audit matter. Changes in reserve assumptions could have had a significant impact on the determination on the Company’s ability to realize the Canadian operation’s deferred income tax asset and the amount of a valuation allowance, if any. A high degree of auditor judgment was required in evaluating the Canadian reserve assumptions which were inputs to derive the recognized deferred income tax asset. Additionally, the evaluation of this estimate required specialized skills and knowledge.

4 ENERPLUS 2020 FINANCIAL SUMMARY

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the realizability of the Canadian deferred income tax assets, including controls over the estimation of the Canadian reserves and the related reserve assumptions. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists engaged by the Company, who estimated the Canadian reserves. We evaluated the methodology used by independent reservoir engineering specialists to estimate the Canadian reserves for compliance with regulatory standards. We compared the 2020 actual production, operating, royalty and capital costs of the Canadian operations to those estimates used in the prior year’s estimate of the proved reserves associated with the Canadian operations to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the Canadian reserves by comparing them to those published by other reserve engineering firms. We assessed the estimates of forecasted production and forecasted operating, royalty and capital cost assumptions used in the Canadian reserves by comparing them to historical results. We involved Canadian income tax professionals with specialized skills and knowledge who assisted in evaluating the application of relevant tax laws and regulations used in the determination of the recognized deferred income tax asset.

Impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to oil and gas properties.

As discussed in Note 2(d) to the consolidated financial statements, the Company depletes its oil and gas properties each quarter using the unit-of-production method on a country-by-country basis for Canada and the United States of America. Under such method, capitalized costs by country are depleted over the estimated proved oil and gas reserves for each of Canada and the United States of America (“country proved reserves”). For the year ended December 31, 2020, the Company recorded depletion, depreciation and accretion expense of $293 million. Additionally, as discussed in Note 2(d) to the consolidated financial statements, the Company is required to perform a quarterly ceiling test calculation on a country-by-country basis for Canada and the United States of America. For the year ended December 31, 2020, the Company recorded ceiling test impairments of $995 million. The Company limits the capitalized costs of proved and unproved oil and natural gas properties, net of accumulated depletion and the related deferred income tax effects, by country, to the estimated future net cash flows from country proved reserves discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved oil and gas properties. The estimation of country proved reserves, which are used in the calculations of depletion and the ceiling test, requires the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The estimated future net cash flows are calculated using the simple average of the preceding twelve months’ first-day-of-the-month commodity prices. The Company engages independent reservoir engineering specialists to estimate country proved reserves.

We identified the assessment of the impact of estimated country proved reserves on the calculations of depletion expense and the ceiling test related to oil and gas properties as a critical audit matter. Changes in reserve assumptions could have had a significant impact on the calculations of depletion expense and the ceiling tests. A high degree of auditor judgment was required in evaluating the country proved reserves, and related reserve assumptions, which were an input to the calculations of depletion expense and the ceiling test.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the calculations of depletion expense and the ceiling test, including controls over the estimation of the country proved reserves and the related reserve assumptions. We assessed the calculations of depletion expense and the ceiling test for compliance with regulatory standards. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists engaged by the Company, who estimated the country proved reserves. We evaluated the methodology used by the independent reservoir engineering specialists to estimate country proved reserves for compliance with regulatory standards. We compared the Company’s 2020 actual production, operating, royalty and capital costs by country to those estimates used in the prior year estimate of country proved reserves to assess the Company’s ability to accurately forecast. We assessed the estimates of forecasted production and forecasted operating, royalty and capital cost assumptions used in the country proved reserves by comparing them to historical results.

Valuation of goodwill for the U.S. reporting unit

As discussed in note 5(b) to the consolidated financial statements the Company recorded goodwill impairment of $203 million related to the U.S. reporting unit. The Company assesses goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to the reporting unit’s fair value. The estimated fair value of the U.S. reporting unit involves a number of estimates, including the future cash flows associated with the estimated proved oil and gas reserves of the U.S. reporting unit (“U.S. proved reserves”) and the discount rate. The estimation of future cash flows associated with the U.S. proved reserves, requires the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The Company engages independent reservoir engineering specialists to estimate the U.S. proved reserves.

ENERPLUS 2020 FINANCIAL SUMMARY 5

We identified the assessment of the valuation of goodwill for the U.S. reporting unit as a critical audit matter. Changes in reserve assumptions and the discount rate could have had a significant impact on the calculation of the fair value of the U.S. reporting unit. A high degree of auditor judgment was required in evaluating the Company’s estimate of future cash flows associated with the U.S. proved reserves, and related reserve assumptions, and the discount rate, which were inputs to the calculation of the fair value of the U.S. reporting unit. Additionally, the evaluation of these estimates required specialized skills and knowledge.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s determination of the fair value of the U.S. reporting unit, including controls related to the development of the discount rate and the estimation of future cash flows associated with the U.S. proved reserves and the related reserve assumptions. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists engaged by the Company, who estimated the U.S. proved reserves. We evaluated the methodology used by the independent reservoir engineering specialists to estimate the U.S. proved reserves for compliance with regulatory standards. We compared the Company’s 2020 actual production, operating, royalty and capital costs of the U.S. reporting unit to those estimates used in the prior year’s estimate of the U.S. proved reserves to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the U.S. proved reserves by comparing them to those published by other reserve engineering firms. We assessed the estimates of forecasted production and forecasted operating, royalty and capital cost assumptions used in the U.S. proved reserves by comparing them to historical results. We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s determination of the discount rate, by comparing the inputs to the discount rate to publicly available market data for comparable entities and assessing the resulting discount rate. The valuations specialist evaluated the Company’s estimate of fair value of the U.S. reporting unit by comparing it to publicly available market data and valuation metrics for comparable entities or asset transactions.

/s/ KPMG LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 2017.

Calgary, Canada

February 18, 2021

6 ENERPLUS 2020 FINANCIAL SUMMARY

STATEMENTS

Consolidated Balance Sheets


(CDN$ thousands)	Note	December 31, 2020		December 31, 2019
Assets
Current assets
Cash and cash equivalents		$	114,455	$	151,649
Accounts receivable	3		106,209		176,119
Income tax receivable	13		167		27,770
Derivative financial assets	15		3,550		10,570
Other current assets			7,137		2,990
			231,518		369,098
Property, plant and equipment:
Crude oil and natural gas properties (full cost method)	4, 5		575,559		1,547,362
Other capital assets, net	4		19,524		20,244
Property, plant and equipment			595,083		1,567,606
Right-of-use assets	9		32,853		48,729
Goodwill	5, 17		—		194,015
Deferred income tax asset	13		607,001		372,502
Income tax receivable	13		—		13,852
Total Assets		$	1,466,455	$	2,565,802

Liabilities
Current liabilities
Accounts payable	6	$	251,822	$	291,540
Dividends payable			2,225		2,217
Current portion of long-term debt	7		103,836		105,998
Derivative financial liabilities	15		19,261		2,734
Current portion of lease liabilities	9		13,391		17,541
			390,535		420,030
Long-term debt	7		386,586		500,635
Asset retirement obligation	8		130,208		138,049
Lease liabilities	9		23,446		35,530
			540,240		674,214
Total Liabilities			930,775		1,094,244

Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: December 31, 2020 – 223 million shares
December 31, 2019 – 222 million shares	14		3,096,969		3,088,094
Paid-in capital			50,604		59,490
Accumulated deficit			(2,932,017)		(1,984,365)
Accumulated other comprehensive income			320,124		308,339
			535,680		1,471,558
Total Liabilities & Shareholders' Equity		$	1,466,455	$	2,565,802

Commitments and Contingencies	16
Subsequent Events	19

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

Approved on behalf of the Board of Directors:


/s/ Hilary Foulkes	/s/ Robert B. Hodgins
Director	Director

ENERPLUS 2020 FINANCIAL SUMMARY 7

Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)


For the year ended December 31 (CDN$ thousands)	Note	2020		2019		2018
Revenues
Crude oil and natural gas sales, net of royalties	10	$	737,205	$	1,254,806	$	1,292,736
Commodity derivative instruments gain/(loss)	15		108,819		(66,071)		88,232
			846,024		1,188,735		1,380,968
Expenses
Operating			263,575		290,766		238,261
Transportation			132,386		144,903		123,463
Production taxes			49,900		83,109		87,286
General and administrative	11		57,583		72,853		75,783
Depletion, depreciation and accretion			293,156		356,830		304,274
Asset impairment	5		994,776		—		—
Goodwill impairment	5		202,767		451,121		—
Interest			28,362		33,919		36,799
Foreign exchange (gain)/loss	12		1,338		(25,378)		39,521
Other expense/(income)			6,303		(7,529)		(5,909)
			2,030,146		1,400,594		899,478
Income/(Loss) Before Taxes			(1,184,122)		(211,859)		481,490
Current income tax expense/(recovery)	13		(14,525)		(33,414)		(27,093)
Deferred income tax expense/(recovery)	13		(246,230)		81,275		130,304
Net Income/(Loss)		$	(923,367)	$	(259,720)	$	378,279

Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation			9,583		(80,602)		125,817
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax			2,202		—		—
Other Comprehensive Income/(Loss)			11,785		(80,602)		125,817

Total Comprehensive Income/(Loss)		$	(911,582)	$	(340,322)	$	504,096

Net Income/(Loss) per Share
Basic	14	$	(4.15)	$	(1.12)	$	1.55
Diluted	14	$	(4.15)	$	(1.12)	$	1.53

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

8 ENERPLUS 2020 FINANCIAL SUMMARY

Consolidated Statements of Changes in Shareholders’ Equity


For the year ended December 31 (CDN$ thousands)	2020		2019		2018
Share Capital
Balance, beginning of year	$	3,088,094	$	3,337,608	$	3,386,946
Purchase of common shares under Normal Course Issuer Bid		(4,731)		(253,920)		(82,596)
Share-based compensation – treasury settled		13,824		4,406		23,389
Stock Option Plan – cash		(218)		—		9,138
Stock Option Plan – exercised		—		—		731
Balance, end of year	$	3,096,969	$	3,088,094	$	3,337,608

Paid-in Capital
Balance, beginning of year	$	59,490	$	46,524	$	75,375
Share-based compensation – cash settled (tax withholding)		(7,232)		(4,952)		—
Share-based compensation – cash settled		—		—		(30,648)
Share-based compensation – equity settled		(13,824)		(4,406)		(23,389)
Share-based compensation – non-cash		12,170		22,324		25,917
Stock Option Plan – exercised		—		—		(731)
Balance, end of year	$	50,604	$	59,490	$	46,524

Accumulated Deficit
Balance, beginning of year	$	(1,984,365)	$	(1,772,084)	$	(2,124,676)
Purchase of common shares under Normal Course Issuer Bid		2,195		75,127		3,569
Net income/(loss)		(923,367)		(259,720)		378,279
Cancellation of predecessor shares		218		—		—
Dividends declared ($0.12 per share)		(26,698)		(27,688)		(29,256)
Balance, end of year	$	(2,932,017)	$	(1,984,365)	$	(1,772,084)

Accumulated Other Comprehensive Income
Balance, beginning of year	$	308,339	$	388,941	$	263,124
Unrealized gain/(loss) on foreign currency translation		9,583		(80,602)		125,817
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax		2,202		—		—
Balance, end of year	$	320,124	$	308,339	$	388,941
Total Shareholders’ Equity	$	535,680	$	1,471,558	$	2,000,989

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENERPLUS 2020 FINANCIAL SUMMARY 9

Consolidated Statements of Cash Flows


For the year ended December 31 (CDN$ thousands)	Note	2020		2019		2018
Operating Activities
Net income/(loss)		$	(923,367)	$	(259,720)	$	378,279
Non-cash items add/(deduct):
Depletion, depreciation and accretion			293,156		356,830		304,274
Asset impairment	5		994,776		—		—
Goodwill impairment	5		202,767		451,121		—
Changes in fair value of derivative instruments	15		23,547		81,733		(124,266)
Deferred income tax expense/(recovery)	13		(246,230)		81,275		130,304
Foreign exchange (gain)/loss on debt and working capital	12		1,931		(34,085)		58,628
Share-based compensation and general and administrative	11, 14		12,726		23,044		25,917
Translation of U.S. dollar cash held in Canada (gain)/loss	12		(1,147)		8,794		(19,630)
Asset retirement obligation expenditures	8		(17,709)		(16,715)		(11,263)
Changes in non-cash operating working capital	18		105,915		1,963		(3,459)
Cash flow from operating activities			446,365		694,240		738,784

Financing Activities
Repayment of senior notes	7		(114,010)		(59,429)		(29,044)
Proceeds from the issuance of shares (net of issue costs)	14		—		—		9,138
Purchase of common shares under Normal Course Issuer Bid	14		(2,536)		(178,793)		(79,027)
Share-based compensation – cash settled (tax withholding)	14		(7,232)		(4,952)		—
Dividends	14,18		(26,690)		(27,866)		(29,282)
Cash flow from/(used in) financing activities			(150,468)		(271,040)		(128,215)

Investing Activities
Capital and office expenditures	18		(333,279)		(606,966)		(604,110)
Property and land acquisitions	4		(10,121)		(24,362)		(18,009)
Property divestments	4		6,145		9,539		(919)
Cash flow from/(used in) investing activities			(337,255)		(621,789)		(623,038)
Effect of exchange rate changes on cash and cash equivalents			4,164		(13,089)		29,248
Change in cash and cash equivalents			(37,194)		(211,678)		16,779
Cash and cash equivalents, beginning of year			151,649		363,327		346,548
Cash and cash equivalents, end of year		$	114,455	$	151,649	$	363,327

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

10 ENERPLUS 2020 FINANCIAL SUMMARY

Notes to Consolidated Financial Statements

1) REPORTING ENTITY

These annual audited Consolidated Financial Statements (“Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (the “Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.

2) SIGNIFICANT ACCOUNTING POLICIES

The following significant accounting policies are presented to assist the reader in evaluating these Consolidated Financial Statements and, together with the following notes, are an integral part of the Consolidated Financial Statements.

a) Basis of Preparation

Enerplus’ Consolidated Financial Statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain prior period amounts have been restated to conform with current period presentation.

i. Reporting Currency

These Consolidated Financial Statements are presented in Canadian dollars, which is Enerplus’ reporting currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand unless otherwise indicated.

ii. Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: crude oil and natural gas reserves and related present value of future cash flows, depreciation, depletion and accretion (“DD&A”), impairment of property, plant and equipment, asset retirement obligations, income taxes, ability to realize deferred income tax assets, impairment assessments of goodwill and the fair value of derivative instruments. The estimation of crude oil and natural gas reserves and the related present value of future cash flows involves the use of independent reservoir engineering specialists and numerous estimates and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these Consolidated Financial Statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies.

In early March 2020, the World Health Organization declared the coronavirus (“COVID-19”) outbreak a pandemic. Responses to the spread of COVID-19 have resulted in a challenging economic climate, with more volatile commodity prices and foreign exchange rates, and a decline in long-term interest rates. Although global economies have begun to recover, markets remain volatile and the timing of a full economic recovery remains uncertain. It is difficult to reliably estimate the length or severity of these developments and their financial impact. The impacts of the economic downturn to Enerplus have been considered in management’s estimates described above at December 31, 2020; however, estimates made during periods of extreme volatility are subject to a higher level of uncertainty and as a result, there may be further prospective material impacts in future periods.

iii. Basis of Consolidation

These Consolidated Financial Statements include the accounts of Enerplus and its subsidiaries. Intercompany balances and transactions are eliminated on consolidation. Interests in jointly controlled crude oil and natural gas assets are accounted for following the concept of undivided interest, whereby Enerplus’ proportionate share of revenues, expenses, assets and liabilities are included in the accounts.

iv. Business Combinations

The acquisition method of accounting is used to account for acquisitions that meet the definition of a business under U.S. GAAP. The cost of an acquisition is measured as the fair value of the assets transferred, equity instruments issued and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.

ENERPLUS 2020 FINANCIAL SUMMARY 11

b) Revenue

Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points.

Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction.

c) Transportation

Enerplus generally sells crude oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which the Company sells crude oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser. In this case, sales are recorded at the price received from the purchaser, net of transportation costs.

Under the other arrangement, Enerplus sells crude oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction. In this case, transportation costs are recorded as transportation expense on the Consolidated Statements of Income/(Loss). Due to these two distinct selling arrangements, Enerplus’ computed realized prices, before the impact of derivative instruments, include revenues which are reported under two separate bases.

d) Crude oil and Natural Gas Properties

Enerplus uses the full cost method of accounting for its crude oil and natural gas properties. Under this method, all acquisition, exploration and development costs incurred in finding crude oil and natural gas reserves are capitalized, including general and administrative costs attributable to these activities. These costs are recorded on a country-by-country cost centre basis as crude oil and natural gas properties subject to depletion (“full cost pool”). Costs associated with production and general corporate activities are expensed as incurred.

The net carrying value of both proved and unproved crude oil and natural gas properties is depleted using the unit of production method using proved reserves, as determined using a constant price assumption of the simple average of the preceding twelve months’ first-day-of-the-month commodity prices (“SEC prices”). The depletion calculation takes into account estimated future development costs necessary to bring those reserves into production.

Under full cost accounting, a ceiling test is performed on a cost centre basis each quarter. Enerplus limits capitalized costs of proved and unproved crude oil and natural gas properties, net of accumulated depletion and the related deferred income tax effects, to the estimated future net cash flows from proved crude oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties (“the ceiling”). This discount rate is not adjusted for current market trends, changes in the cost of capital and the potential impacts, if any, on the discount rate due to climate change factors. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain. The estimated future net cash flows are calculated using the simple average of the preceding twelve months’ first-day-of-the-month commodity prices. If such capitalized costs exceed the ceiling, a write-down equal to that excess is recorded as a non-cash charge to net income. A write-down is not reversed in future periods even if higher crude oil and natural gas prices subsequently increase the ceiling.

Under full cost accounting rules, divestitures of crude oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized.

e) Other Capital Assets

Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, computer equipment and Company owned line-fill in third party pipelines. Line fill is recorded at lower of cost and net realizable value. Depreciation is calculated on a straight-line basis over the estimated useful life of the respective asset. The cost of repairs and maintenance is expensed as incurred.

12 ENERPLUS 2020 FINANCIAL SUMMARY

f) Cash and Cash Equivalents

Cash and cash equivalents includes cash and highly liquid investments with maturities of less than 90 days.

g) Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The portion of goodwill that related to U.S. operations fluctuated due to changes in foreign exchange rates. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes.

Goodwill is assessed for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to the reporting unit’s fair value, with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss). The loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The estimated fair value of the reporting unit involves numerous estimates including the estimated cash flows from proved reserves (and in certain periods probable reserves) associated with the reporting unit and the appropriate discount rate to apply to the estimated cash flows. The discount rate is based on the estimated cost of capital.

h) Asset Retirement Obligations

Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning and site remediation activities. Enerplus recognizes a liability for the estimated present value of the future asset retirement obligation liability at each balance sheet date. Upon recognition, the liability is recorded at its estimated fair value. The associated asset retirement cost is capitalized and amortized over the same period as the underlying asset. Changes in the estimated liability and related asset retirement cost can arise as a result of revisions in the estimated amount or timing of cash flows.

Depletion of asset retirement costs and increases in asset retirement obligations resulting from the passage of time are recorded to depreciation, depletion and accretion and charged against net income in the Consolidated Statements of Income/(Loss).

i) Leases

Enerplus determines if an arrangement is a lease at inception. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating and finance leases are included in right-of-use (“ROU”) assets and the associated lease liability in the Consolidated Balance Sheet.

ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Lease liabilities are recognized at lease commencement date based on the present value of remaining lease payments over the lease term. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for lease incentives received. Enerplus uses the implicit rate when readily available, or uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is reasonably certain that it will exercise those options. Lease expense for operating leases is recognized on a straight-line basis over the lease term.

Lease agreements contain both lease and non-lease components which are accounted for separately. For certain equipment leases, a portfolio approach is applied to effectively account for the ROU assets and liabilities. Prior to January 1, 2019, the Company applied lease accounting in accordance with ASC 840. Results reported for 2020 and 2019 reflect the application of the new guidance while the 2018 comparative results were prepared and reported under previous lease guidance.

j) Income Tax

Enerplus uses the liability method of accounting for income taxes. Deferred income tax assets and liabilities are recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax assets are reviewed each period and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. Enerplus considers both positive and negative evidence including historic and expected future taxable income, reversing existing temporary differences and tax basis carry forward periods in making this assessment.

ENERPLUS 2020 FINANCIAL SUMMARY 13

The expected future taxable income considered in the analysis of the valuation allowance is based on cash flows from the proven and probable reserves. The estimated cash flows from proven and probable reserves is subject to numerous estimates and judgments and involves the use of independent reserve evaluators. A valuation allowance is removed in any period where available evidence indicates all or a portion of the valuation allowance is no longer required. The financial statement effect of an uncertain tax position is recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. Penalties and interest expense related to income tax are recognized in income tax expense.

k) Financial Instruments

i. Fair Value Measurements

Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. For financial instruments carried at fair value, and when disclosing the fair value of financial instruments on certain non-financial items, inputs used in determining the fair value are characterized according to the following fair value hierarchy:

● Level 1 – Inputs represent quoted market prices in active markets for identical assets or liabilities.

● Level 2 – Inputs other than quoted market prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quoted market prices for similar assets or liabilities in active markets or other market corroborated inputs.

● Level 3 – Inputs that are not observable from objective sources, such as forward prices supported by little or no market activity or internally developed estimates of future cash flows used in a present value model.

Subsequent measurement is based on classification of the financial instrument into one of the following five categories: held-for-trading, held-to-maturity, available-for-sale, loans and receivables or other financial liabilities.

ii. Non-derivative financial instruments

The carrying amount of cash, accounts receivable, income tax receivable, accounts payable, dividends payable and bank credit facilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of the senior notes are considered a level 2 fair value measurement. The fair value of debt has been disclosed in Note 15.

The Company uses the current expected credit loss model for its accounts receivable, which requires the use of a lifetime expected loss provision. In making an assessment as to whether financial assets are credit-impaired, the Company considers: (i) historically realized bad debts; (ii) a counterparty’s present financial condition and whether a counterparty has breached certain contracts; (iii) the probability that a counterparty will enter bankruptcy or other financial reorganization; (iv) changes in economic conditions that correlate to increased levels of default; and (v) the term to maturity of the specified receivable. The carrying amounts of receivables are reduced by the amount of the expected credit loss through an allowance account and losses are recognized within general and administrative expense in the Consolidated Statement of Income/(Loss). If the Company subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account.

Enerplus has designated certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. These non-derivative financial instruments will be accounted for under hedge accounting. To be accounted for as a hedge, the U.S. dollar denominated debt must be designated as an effective hedge, both at inception and on an ongoing basis. The required hedge documentation defines the relationship between the U.S. dollar denominated debt and the net investment in the U.S. subsidiary, as well as the Company’s risk management objective and strategy for undertaking the hedging transaction. The Company formally assesses, both at inception and on an ongoing basis, whether the changes in fair value of the U.S. dollar denominated debt are highly effective in offsetting changes in fair value of the net investment in the U.S. subsidiary. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in Other Comprehensive Income/(Loss), net of tax, and are limited to the translation gain or loss on the net investment. Prior to January 1, 2020, the Company did not apply hedge accounting to the net investment in foreign operations and unrealized gains and losses were recognized in net income/loss at the end of the respective reporting period.

14 ENERPLUS 2020 FINANCIAL SUMMARY

A reduction in the fair value of the net investment in the U.S. subsidiary or increase in the U.S. dollar denominated debt may result in a portion of the hedge becoming ineffective. If the hedging relationship ceases to be effective or is terminated, hedge accounting is not applied and subsequent gains or losses are recorded through net income/(loss).

iii. Derivative financial instruments

Enerplus enters into financial derivative contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations.

Enerplus has not designated its financial derivative contracts as effective accounting hedges and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all remaining financial derivative contracts are classified as held-for-trading and are recorded at fair value based on a Level 2 designation, with changes in fair value recorded in net income. The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance sheet date. Enerplus’ accounting policy is to not offset the fair values of its financial derivative assets and liabilities.

Realized gains and losses from commodity price risk management activities are recognized in income when the contract is settled. Unrealized gains and losses on commodity price risk management activities are recognized in income based on the changes in fair value of the contracts at the end of the respective reporting period.

Enerplus’ crude oil, natural gas and natural gas liquids physical delivery purchase and sales contracts qualify as normal purchases and sales as they are entered into and held for the purpose of receipt or delivery of products in accordance with the Company’s expected purchase, sale or usage requirements. As such, these contracts are not considered derivative financial instruments. Settlements on these physical contracts are recognized in net income over the term of the contracts as they occur.

l) Foreign Currency

i. Foreign currency transactions

Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars) using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency of the entity using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Foreign currency differences arising on translation are recognized in net income in the period in which they arise.

ii. Foreign operations

Assets and liabilities of Enerplus’ U.S. operations, which has a U.S. dollar functional currency, are translated into Canadian dollars at period end exchange rates while revenues and expenses are translated using average rates for the period. Gains and losses from the translation are deferred and included in the cumulative translation adjustment which is recorded in accumulated other comprehensive income.

m) Share-Based Compensation

Enerplus’ share-based compensation plans include equity-settled Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) awards made pursuant to its Share Award Incentive Plan (“SAIP”). The Company is authorized to issue up to 4.5% of outstanding common shares from treasury under the SAIP. Enerplus also has a cash-settled Deferred Share Unit (“DSU”) Plan for Directors (“Director DSU Plan”) and a cash-settled RSU Plan for Directors (“Director RSU Plan”).

i. Long-term Incentive (“LTI”) Plans

For RSU awards granted under the SAIP, employees receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and vests one-third each year for three years. The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period.

For PSU awards granted under the SAIP, executives and management receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and they vest at the end of three years. The value upon vesting is based on the value of the underlying shares plus notional accrued dividends along with a multiplier that ranges from 0 to 2 depending on Enerplus’ performance compared to a peer group of both Canadian and U.S. crude oil and natural gas producers over the vesting period.

ENERPLUS 2020 FINANCIAL SUMMARY 15

Under Enerplus’ Director DSU Plan and Director RSU Plan, directors receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded is based on the annual equity retainer value. Directors may elect to receive all or a portion of their notional shares under either plan. Under the Director DSU Plan, units vest and are paid at a specified date following the director leaving the Board. Under the Director RSU Plan, units vest one-third each year for three years. The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period. All Director DSU and RSU grants are settled in cash.

Enerplus recognizes non-cash share-based compensation expense over the vesting period of the equity-settled long-term incentive plans, net of realized forfeitures, based on the estimated grant date share price fair value of the respective awards. The grant date fair value is based on the Company’s 20 day volume weighted average price on December 31 prior to the grant date. The fair value for the PSUs is adjusted for the outcome of the performance condition. Share-based compensation charges are recorded on the Consolidated Statements of Income/(Loss) with an offset to paid-in capital. Each period, management performs an estimate of the PSU plan multiplier. Any differences that arise between the actual multiplier on plan settlement and management’s estimate is recorded to share-based compensation. On settlement of these plans, amounts previously recorded to paid-in capital are reclassified to share capital.

Enerplus recognizes a liability with respect to its cash-settled long-term incentive plans based on their estimated fair value. The liability is re-measured at each reporting date and at settlement date with any changes in the fair value recorded as share-based compensation, included in general and administrative expense.

ii. Stock options

Enerplus’ Stock Option Plan was suspended in 2014 and is now closed. Remaining outstanding stock options expired in March 2020.

n) Net Income/(Loss) Per Share

Basic net income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding during the period.

For the diluted net income per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income. The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all stock options and outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price.

o) Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recognized when it is probable that a liability has been incurred and the amount can be reasonably estimated. Contingencies are adjusted as additional information becomes available or circumstances change.

p) Accounting Changes and Recent Pronouncements Issued

Except for the changes below, the Company has consistently applied the accounting policies to all periods presented in these Consolidated Financial Statements, effective January 1, 2020:

●

ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) – The change was applied prospectively and was applied to the 2020 impairment of goodwill (Refer to Note 5).

●

ASC 815 – Derivatives and Hedging – relating to the net investment in foreign operations for which the U.S. dollar is the functional currency. Effective January 1, 2020, foreign exchange gains and losses on Enerplus’ U.S. denominated debt are recorded in other comprehensive income along with translation gains and losses on Enerplus’ net investment in the U.S. Hedge accounting was applied prospectively thus the change did not impact comparative figures.

●

ASC 326 – Financial Instruments – Credit Losses – modified retrospective method. The adoption of the standard had no impact on the financial statements.

3) ACCOUNTS RECEIVABLE


($ thousands)	December 31, 2020		December 31, 2019
Accrued revenue	$	93,147	$	142,048
Accounts receivable – trade		16,641		37,736
Allowance for doubtful accounts		(3,579)		(3,665)
Total accounts receivable, net of allowance for doubtful accounts	$	106,209	$	176,119

16 ENERPLUS 2020 FINANCIAL SUMMARY

4) PROPERTY, PLANT AND EQUIPMENT (“PP&E”)


			Accumulated Depletion,
As at December 31, 2020			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties⁽¹⁾	$	15,227,076	$	(14,651,517)	$	575,559
Other capital assets		127,527		(108,003)		19,524
Total PP&E	$	15,354,603	$	(14,759,520)	$	595,083


			Accumulated Depletion,
As at December 31, 2019			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties⁽¹⁾	$	15,088,724	$	(13,541,362)	$	1,547,362
Other capital assets		125,265		(105,021)		20,244
Total PP&E	$	15,213,989	$	(13,646,383)	$	1,567,606

(1)	All of the Company’s unproved properties are included in the full cost pool.

Acquisitions:

For the years ended December 31, 2020 and 2019, Enerplus acquired property and land totaling $10.1 million and $24.4 million, respectively.

Divestments:

For the years ended December 31, 2020 and 2019, Enerplus disposed of properties for proceeds of $6.1 million and $9.6 million, respectively.

5) IMPAIRMENT

a) Impairment of PP&E


($ thousands)	2020		2019		2018
Crude oil and natural gas properties:
Canada cost centre	$	134,349	$	—	$	—
U.S. cost centre		860,427		—		—
Total impairment expense	$	994,776	$	—	$	—

The PP&E impairments for the year ended December 31, 2020 were due to lower twelve-month average trailing crude oil and natural gas prices. There was no PP&E impairments recorded for the years ended December 31, 2019 and 2018. The primary factors that will affect future ceiling values include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, and production levels. The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test as at December 31, 2020, 2019 and 2018:


	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub Gas		Exchange Rate
Period	US$/bbl		CDN$/bbl		US$/Mcf		US$/CDN
2020	$	39.54	$	45.56	$	2.00		1.34
2019		55.85		66.73		2.58		1.33
2018		65.56		69.58		3.10		1.28

b) Impairment of Goodwill

Enerplus recorded goodwill impairment of $202.8 million related to its U.S. reporting unit for the year ended December 31, 2020 (December 31, 2019 - $451.1 million for the Canadian reporting unit). The impairment was a result of lower commodity prices, which resulted in a reduction in the fair value of the U.S. reporting unit. The U.S reporting unit for the goodwill impairment test was based on its reserve values at forecasted prices and costs at June 30^,2020. At December 31, 2020, there was no goodwill remaining on the Company’s Condensed Consolidated Balance Sheet. There was no goodwill impairment for the year ended December 31, 2018.

ENERPLUS 2020 FINANCIAL SUMMARY 17

The fair value of the U.S. reporting unit was estimated using proved reserves as at the measurement date base on forward price curves as determined by external reserve engineers and discounted using an estimated after-tax discount rate of 15%. The estimated fair value of the reporting units is considered a level 3 fair value under the fair value hierarchy.

6) ACCOUNTS PAYABLE


($ thousands)	December 31, 2020		December 31, 2019
Accrued payables	$	107,254	$	105,928
Accounts payable – trade		144,568		185,612
Total accounts payable	$	251,822	$	291,540

7) DEBT


($ thousands)	December 31, 2020		December 31, 2019
Current:
Senior notes	$	103,836	$	105,998
Long-term:
Bank credit facility	$	—	$	—
Senior notes		386,586		500,635
Total debt	$	490,422	$	606,633

Bank Credit Facility

Enerplus has a senior unsecured, covenant-based, US$600 million bank credit facility that matures on October 31, 2023. Drawn fees range between 125 and 315 basis points over bankers’ acceptance and LIBOR rates. Standby fees on the undrawn portion of the facility are based on 20% of the drawn pricing. The Company has the ability to request an extension of the facility or repay the entire balance at the end of the term. At December 31, 2020, Enerplus was undrawn on the facility (December 31, 2019 –undrawn).

Senior Notes

During 2020, Enerplus made its fourth US$22 million principal repayment on its 2009 senior notes and its first US$59.6 million principal repayment on its 2012 senior notes. During 2019, Enerplus made its third US$22 million principal repayment on its 2009 senior notes and a $30 million bullet repayment on its 2012 senior notes. During 2018, Enerplus made its second US$22 million principal repayment on its 2009 senior notes.

The terms and rates of the Company’s outstanding senior notes are detailed below:

Original

Remaining

CDN$ Carrying

Coupon

Principal

Value

Issue Date

Interest Payment Dates

Principal Repayment

Rate

($ thousands)

September 3, 2014

March 3 and Sept 3

5 equal annual installments beginning September 3, 2022

3.79%

US$200,000

US$105,000

133,613

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2022

4.40%

US$20,000

25,450

May 15, 2012

May 15 and Nov 15

4 equal annual installments beginning May 15, 2021

4.40%

US$355,000

US$238,400

303,364

June 18, 2009

June 18

Final installment on June 18, 2021

7.97%

US$225,000

US$22,000

27,995

Total carrying value

490,422

18 ENERPLUS 2020 FINANCIAL SUMMARY

8) ASSET RETIREMENT OBLIGATION


($ thousands)	December 31, 2020		December 31, 2019
Balance, beginning of year	$	138,049	$	126,112
Change in estimates		1,331		23,362
Property acquisition and development activity		2,246		2,068
Divestments		(1,030)		(2,760)
Settlements		(17,709)		(16,715)
Accretion expense		7,321		5,982
Balance, end of year	$	130,208	$	138,049

Enerplus has estimated the present value of its asset retirement obligation to be $130.2 million at December 31, 2020 based on a total undiscounted, uninflated liability of $348.4 million (December 31, 2019 – $138.0 million and $344.7 million, respectively). The asset retirement obligation was calculated using a weighted average credit-adjusted risk-free rate of 5.35% and inflation rate of 0.9% (December 31, 2019 – 5.50% and 1.8%, respectively). The majority of Enerplus’ asset retirement obligation expenditures are expected to be incurred between 2024 and 2046.

9) LEASES

The Company incurs lease payments related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which include the assessment of the appropriate durations for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Consolidated Balance Sheet. Such items are charged to operating expenses and general and administrative expenses in the Consolidated Statement of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with other U.S. GAAP.


($ thousands)	December 31, 2020		December 31, 2019
Assets
Operating right-of-use assets	$	32,853	$	48,729
Liabilities
Current operating lease liabilities	$	13,391	$	17,541
Non-current operating lease liabilities		23,446		35,530
Total lease liabilities	$	36,837	$	53,071

Weighted average remaining lease term (years)
Operating leases		3.9		4.3

Weighted average discount rate
Operating leases		4.2%		4.1%

The components of lease expense for the year ended December 31, 2020 and 2019 are as follows:



($ thousands)	2020		2019
Operating lease cost	$	16,585	$	19,546
Variable lease cost		1,753		(63)
Short-term lease cost		9,512		15,332
Sublease income		(1,476)		(1,072)
Total	$	26,374	$	33,743

ENERPLUS 2020 FINANCIAL SUMMARY 19

Maturities of lease liabilities, all of which are classified as operating leases at December 31, 2020, are as follows:


Maturity of Lease Liabilities
($ thousands)	Operating Leases
2021	$	14,643
2022		8,285
2023		6,963
2024		6,202
2025		1,202
After 2025		2,696
Total lease payments	$	39,991
Less imputed interest		(3,154)
Total discounted lease payments	$	36,837
Current portion of lease liabilities	$	13,391
Non-current portion of lease liabilities	$	23,446

Supplemental information related to leases are as follows:



($ thousands)	2020			2019
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases	$	16,142	$	18,637
Right-of-use assets obtained/(terminated) in exchange for lease obligations:
Operating leases	$	(1,752)	$	20,818

10) CRUDE OIL AND NATURAL GAS SALES


($ thousands)	2020		2019		2018
Crude oil and natural gas sales	$	923,546	$	1,572,955	$	1,610,899
Royalties⁽¹⁾		(186,341)		(318,149)		(318,163)
Crude oil and natural gas sales, net of royalties	$	737,205	$	1,254,806	$	1,292,736

(1)	Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss).

Crude oil and natural gas revenue by country and by product for the years ended December 31, 2020 and 2019 are as follows:


2020		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	96,498	$	78,798	$	12,307	$	3,452	$	1,942
United States		640,707		508,294		119,030		13,233		149
Total	$	737,205	$	587,092	$	131,337	$	16,685	$	2,091


2019		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties⁽¹⁾		Crude oil⁽²⁾		gas⁽²⁾		liquids⁽²⁾		Other⁽³⁾
Canada	$	177,299	$	145,814	$	21,776	$	7,158	$	2,551
United States		1,077,507		847,182		215,963		14,355		7
Total	$	1,254,806	$	992,996	$	237,739	$	21,513	$	2,558

(1)	Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss).

(2)	U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties.

(3)	Includes third party processing income.

Enerplus sells the majority of its production pursuant to variable-price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under the contracts, the Company is required to deliver a fixed or variable volume of crude oil, natural gas liquids or natural gas to the contract counterparty.

Crude oil, natural gas and natural gas liquids are sold under contracts of varying terms, including multi-year contracts. Revenues are typically collected in the month following production.

20 ENERPLUS 2020 FINANCIAL SUMMARY

11) GENERAL AND ADMINISTRATIVE EXPENSE


($ thousands)	2020		2019		2018
General and administrative expense⁽¹⁾	$	44,584	$	49,532	$	49,943
Share-based compensation expense		12,999		23,321		25,840
General and administrative expense	$	57,583	$	72,853	$	75,783

(1)	Includes non-cash lease expense/(inducement) of $(288) in 2020 and $(720) in 2019.

12) FOREIGN EXCHANGE


($ thousands)	2020		2019		2018
Realized:
Foreign exchange (gain)/loss	$	554	$	(87)	$	523
Translation of U.S. dollar cash held in Canada (gain)/loss		(1,147)		8,794		(19,630)
Unrealized:
Translation of U.S. dollar debt and working capital (gain)/loss		1,931		(34,085)		58,628
Foreign exchange (gain)/loss	$	1,338	$	(25,378)	$	39,521

13) INCOME TAXES

Enerplus’ provision for income tax is as follows:


($ thousands)	2020		2019		2018
Current tax
Canada	$	—	$	(13,910)	$	(400)
United States		(14,525)		(19,504)		(26,693)
Current tax expense/(recovery)		(14,525)		(33,414)		(27,093)
Deferred tax
Canada	$	(24,584)	$	11,023	$	3,915
United States		(221,646)		70,252		126,389
Deferred tax expense/(recovery)		(246,230)		81,275		130,304
Income tax expense/(recovery)	$	(260,755)	$	47,861	$	103,211

The following provides a reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes:


($ thousands)	2020		2019		2018
Income/(loss) before taxes
Canada	$	(13,507)	$	(437,571)	$	104,204
United States		(1,170,615)		225,712		377,286
Total income/(loss) before taxes		(1,184,122)		(211,859)		481,490
Canadian statutory rate		24.00%		26.50%		27.00%
Expected income tax expense/(recovery)	$	(284,189)	$	(56,143)	$	130,002
Impact on taxes resulting from:
Foreign and statutory rate differences	$	(37,451)	$	27,446	$	(23,859)
Share-based compensation		2,073		(5,398)		(18,102)
Capital gains and losses		17,261		3,994		7,254
Change in valuation allowance		(31,195)		(22,038)		6,292
Amounts in respect of prior periods		8,905		(19,451)		—
Non-deductible goodwill impairment and other expenses		63,841		119,451		1,624
Income tax expense/(recovery)	$	(260,755)	$	47,861	$	103,211

During the year, the Alberta corporate income tax rate change resulted in a decrease to the Canadian statutory rate by 2.5% for 2020.

ENERPLUS 2020 FINANCIAL SUMMARY 21

The deferred income tax asset consists of the following:


As at December 31 ($ thousands)	2020		2019
Deferred income tax assets
Property, plant and equipment	$	177,799	$	59,896
Tax loss carry-forwards and other credits		385,934		383,600
Capital loss carryforwards and other capital items		141,880		154,532
Asset retirement obligation		31,793		33,569
Derivative financial instruments		3,723		—
Other assets		8,486		12,219
Deferred income tax assets before valuation allowance		749,615		643,816
Valuation allowance		(142,614)		(169,129)
Deferred income tax assets, net		607,001		474,687
Deferred income tax liabilities
Property, plant and equipment	$	—	$	(100,328)
Derivative financial instruments		—		(1,857)
Total deferred income tax liabilities		—		(102,185)
Total deferred income tax asset	$	607,001	$	372,502

In 2020, $14.5 million was reclassified from deferred income tax asset to income tax receivable for the recognition of the final portion of the AMT refund. As of December 31, 2020, all outstanding AMT refunds have been received.

Loss carryforwards available for tax reporting purposes:


As at December 31 ($ thousands)	2020		Expiration Date
Canada
Capital losses	$	1,053,000	Indefinite
Non-capital losses		284,000	2031-2039
United States
Net operating losses – prior to 2018	$	875,000	2030-2040
Net operating losses – 2018 and thereafter		316,000	Indefinite

Changes in the balance of Enerplus’ unrecognized tax benefits are as follows:


($ thousands)	2020		2019		2018
Balance, beginning of year	$	—	$	13,300	$	13,300
Increase - tax positions in prior periods		21,030		—		—
Settlements		—		(13,300)		—
Balance, end of year	$	21,030	$	—	$	13,300

If recognized, all of Enerplus’ unrecognized tax benefits as at December 31, 2020 would affect Enerplus’ effective income tax rate. It is not anticipated that the amount of unrecognized tax benefits will significantly change during the next 12 months.

A summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities are as follows:


Jurisdiction		Taxation Years
Canada – Federal		2015-2020
United States – Federal		2017-2020

Enerplus and its subsidiaries file income tax returns primarily in Canada and the United States. Matters in dispute with the taxation authorities are ongoing and in various stages of completion.

22 ENERPLUS 2020 FINANCIAL SUMMARY

14) SHAREHOLDERS’ EQUITY

a) Share Capital


	2020			2019			2018
Authorized: unlimited number of common shares Issued: (thousands)	Shares	Amount		Shares	Amount		Shares	Amount
Balance, beginning of year	221,744	$	3,088,094	239,411	$	3,337,608	242,129	$	3,386,946
Issued for cash:
Purchase of common shares under Normal Course Issuer Bid	(340)		(4,731)	(18,231)		(253,920)	(5,925)		(82,596)
Stock Option Plan	—		—	—		—	668		9,138
Non-cash:
Share-based compensation – settled⁽¹⁾	1,160		13,824	564		4,406	2,539		23,389
Stock Option Plan – exercised	—		—	—		—	—		731
Cancellation of predecessor shares	(16)		(218)	—		—	—		—
Balance, end of year	222,548	$	3,096,969	221,744	$	3,088,094	239,411	$	3,337,608

(1)	The amount of shares issued on LTI settlement is net of employee withholding taxes in 2020 and 2019.

The Company is authorized to issue an unlimited number of common shares without par value.

For the year ended December 31, 2020, Enerplus declared dividends of $0.12 per weighted average common share totaling $26.7 million (December 31, 2019 - $0.12 per share and $27.7 million, December 31, 2018 – $0.12 per share and $29.3 million).

Enerplus’ Normal Course Issuer Bid (“NCIB”) expired on March 25, 2020. All repurchases were made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess allocated to accumulated deficit.

For the year ended December 31, 2020, the Company repurchased 340,434 common shares under the NCIB at an average price of $7.44 per share, for total consideration of $2.5 million. Of the amount paid, $4.7 million was charged to share capital and $2.2 million was credited to accumulated deficit.

For the year ended December 31, 2019, the Company repurchased 18,231,401 common shares under the NCIB at an average price of $9.80 per share, for total consideration of $178.8 million. Of the amount paid, $253.9 million was charged to share capital and $75.1 million was credited to accumulated deficit.

b) Share-based Compensation

The following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss):


($ thousands)	2020		2019		2018
Cash:
Long-term incentive plans expense	$	(1,411)	$	689	$	133
Non-Cash:
Long-term incentive plans expense		13,014		22,324		25,917
Equity swap (gain)/loss		1,396		308		(210)
Share-based compensation expense	$	12,999	$	23,321	$	25,840

i) LTI Plans

The following table summarizes the PSU, RSU and DSU activity for the year ended December 31, 2020:


For the year ended December 31, 2020	Cash-settled LTI Plans	Equity-settled LTI Plans		Total
(thousands of units)	DSU	PSU⁽¹⁾	RSU
Balance, beginning of year	422	2,139	1,531	4,092
Granted	133	1,203	1,142	2,478
Vested	—	(652)	(741)	(1,393)
Forfeited	—	(138)	(107)	(245)
Balance, end of year	555	2,552	1,825	4,932

(1)	Based on underlying awards before any effect of the performance multiplier.

ENERPLUS 2020 FINANCIAL SUMMARY 23

Cash-settled LTI Plans

For the year ended December 31, 2020, the Company recorded a cash share-based compensation recovery of $1.4 million (2019 – expense of $0.7 million; 2018 – expense of $0.1 million).

As of December 31, 2020, a liability of $2.2 million (December 31, 2019 – $3.9 million) with respect to the Director DSU Plan has been recorded to Accounts Payable on the Consolidated Balance Sheets.

Equity-settled LTI Plans

The following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms.


At December 31, 2020 ($ thousands, except for years)	PSU⁽¹⁾		RSU		Total
Cumulative recognized share-based compensation expense	$	18,564	$	13,474	$	32,038
Unrecognized share-based compensation expense		7,444		5,497		12,941
Fair value	$	26,008	$	18,971	$	44,979
Weighted-average remaining contractual term (years)		1.8		1.4

(1)	Includes estimated performance multipliers.

The Company directly withholds shares on PSU and RSU settlements for tax-withholding purposes. For the year ended December 31, 2020 cash withholding taxes of $7.2 million were paid (2019 - $5.0 million, 2018 – nil).

ii) Stock Option Plan

At December 31, 2020, all stock options are fully vested and all non-cash share-based compensation expense has been fully recognized. All remaining outstanding stock options expired in March 2020.

The following table summarizes the stock option plan activity for the year ended December 31, 2020:


	Number of Options	Weighted Average
Year ended December 31, 2020	(thousands)	Exercise Price
Options outstanding, beginning of year	2,107	$	14.24
Exercised	—		—
Forfeited	(8)		14.85
Expired	(2,099)		14.24
Options outstanding and exercisable, end of year	—	$	—

c) Basic and Diluted Net Income/(Loss) Per Share

Net income/(loss) per share has been determined as follows:


(thousands, except per share amounts)	2020		2019		2018
Net income/(loss)	$	(923,367)	$	(259,720)	$	378,279

Weighted average shares outstanding – Basic		222,503		231,334		244,076
Dilutive impact of share-based compensation⁽¹⁾		—		—		3,185
Weighted average shares outstanding – Diluted		222,503		231,334		247,261
Net income/(loss) per share
Basic	$	(4.15)	$	(1.12)	$	1.55
Diluted	$	(4.15)	$	(1.12)	$	1.53

(1)	For the years ended December 31, 2020 and 2019, the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.

24 ENERPLUS 2020 FINANCIAL SUMMARY

15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At December 31, 2020, the senior notes had a carrying value of $490.4 million and a fair value of $494.1 million (December 31, 2019 – $606.6 million and $613.8 million, respectively). The fair value of the senior notes is estimated based on the amount that Enerplus would have to pay a third party to assume the debt, including the credit spread for the difference between the issue rate and the period end market rate. The period end market rate is estimated by comparing the debt to new issuances (secured or unsecured) and secondary trades of similar size and credit statistics for both public and private debt.

There were no transfers between fair value hierarchy levels during the year.

b) Derivative Financial Instruments

The derivative financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.

The following tables summarize the change in fair value for the respective years:


							Income
Gain/(Loss) ($ thousands)	2020		2019		2018		Statement Presentation
Equity Swaps	$	(1,396)	$	(308)	$	210	G&A expense
Commodity Derivative Instruments:
Oil		(25,701)		(70,481)		114,822	Commodity derivative
Gas		3,550		(10,944)		9,234	instruments
Total Unrealized Gain/(Loss)	$	(23,547)	$	(81,733)	$	124,266

The following table summarizes the effect of Enerplus’ commodity derivative instruments on the Consolidated Statements of Income/(Loss):


($ thousands)	2020		2019		2018
Change in fair value gain/(loss)	$	(22,151)	$	(81,425)	$	124,056
Net realized cash gain/(loss)		130,970		15,354		(35,824)
Commodity derivative instruments gain/(loss)	$	108,819	$	(66,071)	$	88,232

The following table summarizes the fair values at the respective year ends:


	December 31, 2020				December 31, 2019
	Assets		Liabilities			Assets	Liabilities
($ thousands)	Current		Current			Current	Current
Equity Swaps	$	—	$	3,613	$	—	$	2,217
Commodity Derivative Instruments:
Oil		—		15,648		10,570		517
Gas		3,550		—		—		—
Total	$	3,550	$	19,261	$	10,570	$	2,734

The fair value of commodity derivative instruments and the equity swaps is estimated based on commodity and option pricing models that incorporates various factors including forecasted commodity prices, volatility and the credit risk of the entities party to the contract. Changes in commodity prices over the term of the contracts can result in material differences between the estimated fair value at a point in time and the actual settlement amounts of the contracts.

c) Risk Management

In the normal course of operations, Enerplus is exposed to various market risks, including commodity prices, foreign exchange, interest rates, equity prices, credit risk and liquidity risk.

i) Market Risk

Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.

ENERPLUS 2020 FINANCIAL SUMMARY 25

Commodity Price Risk:

Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.

The following tables summarize Enerplus’ price risk management positions at February 18, 2021:

Crude Oil Instruments:



Instrument Type⁽¹⁾⁽²⁾	bbls/day	US$/bbl

Jan 1, 2021 – Mar 31, 2021
WTI Swap	5,000	45.55
WTI Purchased Put	15,000	40.53
WTI Sold Put	15,000	32.00
WTI Sold Call	15,000	50.29

Apr 1, 2021 – Jun 30, 2021
WTI Purchased Put	20,000	40.90
WTI Sold Put	20,000	32.00
WTI Sold Call	20,000	50.72
UHC Differential Swap	1,500	(1.80)

Jul 1, 2021 – Dec 31, 2021
WTI Purchased Put	23,000	46.39
WTI Sold Put	23,000	36.39
WTI Sold Call	23,000	56.70
UHC Differential Swap	1,500	(1.80)

Jan 1, 2022 – Dec 31, 2022
WTI Purchased Put	17,000	50.00
WTI Sold Put	17,000	40.00
WTI Sold Call	17,000	57.91

(1)	Transactions with a common term have been aggregated and presented as the weighted average price/bbl before premiums.

(2)	The total average deferred premium spent on our outstanding hedges is US$0.80/bbl from January 1, 2021 – December 31, 2021 and US$1.50/bbl from January 1, 2022 – December 31, 2022.

Natural Gas Instruments:


Instrument Type	MMcf/day	US$/Mcf

Mar 1, 2021 - Mar 31, 2021
NYMEX Swap	60,000	3.16

Apr 1, 2021 – Oct 31, 2021
NYMEX Swap	60,000	2.90
NYMEX Purchased Put	40,000	2.75
NYMEX Sold Put	40,000	2.15
NYMEX Sold Call	40,000	3.25

Foreign Exchange Risk:

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a significant portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At December 31, 2020, Enerplus did not have any foreign exchange derivatives outstanding.

Interest Rate Risk:

At December 31, 2020, all of Enerplus’ debt was based on fixed interest rates, and Enerplus did not have any interest rate derivatives outstanding.

26 ENERPLUS 2020 FINANCIAL SUMMARY

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps maturing in 2021 that effectively fix the future settlement cost on a portion of its cash settled LTI plans.

ii) Credit Risk

Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.

Enerplus mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.

Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At December 31, 2020, approximately 82% of Enerplus’ marketing receivables were with companies considered investment grade.

Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts off future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus’ allowance for doubtful accounts balance at December 31, 2020 was $3.6 million (December 31, 2019 – $3.7 million).

iii) Liquidity Risk & Capital Management

Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash and cash equivalents) and shareholders’ capital. Enerplus’ objective is to provide adequate short and longer term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities.

Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, as well as acquisition and divestment activity.

At December 31, 2020, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

16) COMMITMENTS AND CONTINGENCIES

a) Commitments

Enerplus has the following minimum annual commitments, excluding operating leases which are recorded in the lease liability (see Note 9):


				Minimum Annual Commitment Each Year
($ thousands)		Total		2021		2022		2023		2024		2025		Thereafter
Senior notes⁽¹⁾	$		490,422	$	103,836	$	128,014	$	102,564	$	102,564	$	26,722	$	26,722
Transportation commitments			289,993		44,539		30,393		29,358		29,088		29,101		127,514
Processing commitments			9,489		1,519		1,519		1,519		1,519		1,519		1,894
Total commitments⁽²⁾⁽³⁾	$		789,904	$	149,894	$	159,926	$	133,441	$	133,172	$	57,343	$	156,131

(1)	Interest payments have not been included.

(2)	Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(3)	US$ commitments have been converted to CDN$ using the December 31, 2020 foreign exchange rate of 1.2725.

ENERPLUS 2020 FINANCIAL SUMMARY 27

b) Contingencies

Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is probable and the amount can be reasonably estimated, an accrual is recorded.

17) GEOGRAPHICAL INFORMATION


As at and for the year ended December 31, 2020 ($ thousands)	Canada		U.S.		Total
Crude oil and natural gas sales, net of royalties	$	96,498	$	640,707	$	737,205
Depletion, depreciation and accretion		46,784		246,372		293,156
Property, plant and equipment		112,195		482,888		595,083
Deferred income tax asset		210,615		396,386		607,001


As at and for the year ended December 31, 2019 ($ thousands)	Canada		U.S.		Total
Crude oil and natural gas sales, net of royalties	$	177,299	$	1,077,507	$	1,254,806
Depletion, depreciation and accretion		59,936		296,894		356,830
Property, plant and equipment		259,514		1,308,092		1,567,606
Deferred income tax asset		185,880		186,622		372,502
Goodwill		—		194,015		194,015
Long term income tax receivable		—		13,852		13,852


As at and for the year ended December 31, 2018 ($ thousands)	Canada		U.S.		Total
Crude oil and natural gas sales, net of royalties	$	198,263	$	1,094,473	$	1,292,736
Depletion, depreciation and accretion		58,333		245,941		304,274
Property, plant and equipment		262,159		1,044,912		1,307,071
Deferred income tax asset		196,903		268,221		465,124
Goodwill		451,121		203,678		654,799
Long term income tax receivable		—		27,195		27,195

18) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital


($ thousands)	December 31, 2020		December 31, 2019		December 31, 2018
Accounts receivable	$	112,041	$	8,493	$	(45,385)
Other assets		(5,611)		4,475		(3,026)
Accounts payable		(515)		(11,005)		44,952
	$	105,915	$	1,963	$	(3,459)

b) Changes in Other Non-Cash Working Capital


($ thousands)	December 31, 2020		December 31, 2019		December 31, 2018
Non-cash financing activities⁽¹⁾	$	8	$	(178)	$	(26)
Non-cash investing activities⁽²⁾	$	(37,509)	$	17,682	$	(3,753)

(1)	Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows.

(2)	Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows.

c) Other


($ thousands)	December 31, 2020		December 31, 2019		December 31, 2018
Income taxes paid/(received)	$	(58,361)	$	(71,890)	$	(481)
Interest paid	$	28,758	$	33,991	$	36,161

28 ENERPLUS 2020 FINANCIAL SUMMARY

19) SUBSEQUENT EVENTS

On January 25, 2021, the Company entered into a purchase agreement to acquire the equity interest of Bruin E&P HoldCo, LLC for total cash consideration of US$465 million, subject to customary purchase price adjustments (the “Bruin Acquisition”). On the same date, we entered into a binding commitment letter for a new three-year senior unsecured US$400 million term loan to be fully drawn down on the closing date of the Bruin Acquisition to pay for a portion of the purchase price. We intend to fund the remaining portion of the purchase price with net proceeds from a $132.3 million bought deal equity financing, issuing 33,062,500 common shares at a price of $4.00 per common share, which we completed on February 3, 2021. The Bruin Acquisition is expected to close in early March 2021.

ENERPLUS 2020 FINANCIAL SUMMARY 29

2020 FINANCIAL SUMMARY

Exhibit 99.3


	Three months ended					Twelve months ended
SELECTED FINANCIAL RESULTS	December 31,					December 31,
		2020		2019			2020		2019
Financial (CDN$, thousands, except ratios)
Net Income/(Loss)		$	(204,167)	$	(429,143)		$	(923,367)	$	(259,720)
Adjusted Net Income⁽¹⁾			22,149		34,365			19,758		243,160
Cash Flow from Operating Activities			96,079		188,492			446,365		694,240
Adjusted Funds Flow⁽¹⁾			91,871		178,922			358,160		708,992
Dividends to Shareholders - Declared			6,677		6,656			26,698		27,688
Total Debt Net of Cash⁽¹⁾			375,967		454,984			375,967		454,984
Capital Spending			52,414		99,389			291,468		618,910
Property and Land Acquisitions			2,061		6,126			10,121		24,406
Property Divestments			47		(316)			6,145		9,583
Net Debt to Adjusted Funds Flow Ratio⁽¹⁾			1.0x		0.6x			1.0x		0.6x

Financial per Weighted Average Shares Outstanding
Net Income/(Loss) - Basic		$	(0.92)	$	(1.93)		$	(4.15)	$	(1.12)
Net Income/(Loss) - Diluted			(0.92)		(1.93)			(4.15)		(1.12)
Weighted Average Number of Shares Outstanding (000’s) - Basic			222,548		222,227			222,503		231,334
Weighted Average Number of Shares Outstanding (000’s) - Diluted			222,548		222,227			222,503		231,334

Selected Financial Results per BOE⁽²⁾⁽³⁾
Crude Oil & Natural Gas Sales⁽⁴⁾		$	30.60	$	41.64		$	27.82	$	42.65
Royalties and Production Taxes			(7.67)		(10.93)			(7.12)		(10.88)
Commodity Derivative Instruments			3.12		0.07			3.95		0.42
Operating Expenses			(8.20)		(8.05)			(7.94)		(7.88)
Transportation Costs			(3.89)		(3.82)			(3.99)		(3.93)
General and Administrative Expenses			(1.46)		(1.34)			(1.35)		(1.32)
Cash Share-Based Compensation			(0.11)		0.01			0.04		(0.02)
Interest, Foreign Exchange and Other Expenses			(0.81)		(0.89)			(1.06)		(0.72)
Current Income Tax Recovery			—		1.41			0.44		0.91
Adjusted Funds Flow⁽¹⁾		$	11.58	$	18.10		$	10.79	$	19.23


	Three months ended					Twelve months ended
SELECTED OPERATING RESULTS	December 31,					December 31,
		2020		2019			2020		2019
Average Daily Production⁽³⁾
Crude Oil (bbls/day)			43,405		54,344			45,421		49,704
Natural Gas Liquids (bbls/day)			5,790		5,502			5,633		4,929
Natural Gas (Mcf/day)			222,293		285,537			237,857		278,451
Total (BOE/day)			86,244		107,436			90,697		101,042

% Crude Oil and Natural Gas Liquids			57%		56%			56%		54%

Average Selling Price⁽³⁾⁽⁴⁾
Crude Oil (per bbl)		$	47.95	$	67.23		$	44.35	$	68.98
Natural Gas Liquids (per bbl)			17.19		18.28			10.29		15.19
Natural Gas (per Mcf)			2.04		2.50			1.87		2.87

Net Wells Drilled			2		9			42		56

(1)	These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See “Non-GAAP Measures” section in the following MD&A.

(2)	Non-cash amounts have been excluded.

(3)	Based on Company interest production volumes. See “Basis of Presentation” section in the following MD&A.

(4)	Before transportation costs, royalties and commodity derivative instruments.

ENERPLUS 2020 FINANCIAL SUMMARY 1


	Three months ended					Twelve months ended
	December 31,					December 31,
Average Benchmark Pricing		2020		2019			2020		2019
WTI crude oil (US$/bbl)		$	42.66	$	56.96		$	39.40	$	57.03
Brent (ICE) crude oil (US$/bbl)			45.24		62.51			43.21		64.18
NYMEX natural gas – last day (US$/Mcf)			2.66		2.50			2.08		2.63
US/CDN average exchange rate			1.30		1.32			1.34		1.33


Share Trading Summary	CDN⁽¹⁾ – ERF		U.S.⁽²⁾ – ERF
For the twelve months ended December 31, 2020	(CDN$)		(US$)
High	$	9.55	$	7.35
Low	$	1.62	$	1.15
Close	$	3.98	$	3.13

(1)	TSX and other Canadian trading data combined.

(2)	NYSE and other U.S. trading data combined.


2020 Dividends per Share		CDN$		US$⁽¹⁾
First Quarter Total	$	0.03	$	0.02
Second Quarter Total	$	0.03	$	0.02
Third Quarter Total	$	0.03	$	0.02
Fourth Quarter Total	$	0.03	$	0.02
Total Year to Date	$	0.12	$	0.08

(1)	CDN$ dividends converted at the relevant foreign exchange rate on the payment date.

2 ENERPLUS 2020 FINANCIAL SUMMARY

2020 HIGHLIGHTS

Financial & Operational Highlights

●

We delivered 2020 production at the high end of our annual guidance ranges, with total production of 90,697 BOE/day, including crude oil and natural gas liquids production of 51,054 bbls/day, a decrease of 10% and 7%, respectively, compared to 2019 due to the temporary curtailment of crude oil production during the second quarter and the significant reduction in capital activity in North Dakota during 2020 in response to the decline in crude oil prices. Natural gas production decreased 15% year-over-year due to lower capital activity for our Marcellus natural gas asset during 2020.

●

Full year 2020 cash flow from operating activities and adjusted funds flow were $446.4 million and $358.2 million, respectively, compared to $694.2 million and $709.0 million, respectively, in 2019. Cash flow from operating activities and adjusted funds flow decreased from 2019 due to lower benchmark crude oil prices and reduced production volumes.

●

We reported a full year 2020 net loss of $923.4 million, or ($4.15) per share, compared to a net loss of $259.7 million, or ($1.12) per share, in 2019. The higher net loss was primarily due to larger non-cash impairment charges, lower benchmark crude oil prices and reduced production volumes in 2020. We recorded non-cash impairments totaling $1,197.6 million in 2020 related to property, plant and equipment (“PP&E”) and goodwill due to the low commodity price environment and the use of 12-month trailing prices to test for impairment, as required under U.S. Securities and Exchange Commission (“SEC”) guidelines. Excluding these impairments and certain other non-cash or non-recurring items, full year 2020 adjusted net income was $19.8 million, or $0.09 per share, compared to $243.2 million, or $1.05 per share, in 2019. Adjusted net income decreased from 2020 due to lower benchmark crude oil prices and reduced production volumes.

●

Our 2020 Bakken crude oil price differential was US$4.96/bbl below WTI, compared to US$3.61/bbl below WTI in 2019. The weaker year-over-year differential was due to the significant benchmark oil price volatility and the narrowing of Brent-WTI differentials in 2020. Our 2020 Marcellus natural gas price differential was US$0.65/Mcf below NYMEX, compared to US$0.39/Mcf below NYMEX in 2019. Regional pricing in the Marcellus was particularly weak from September to November of 2020 due to nearly full regional storage combined with low demand due to mild weather.

●

Operating expenses in 2020 were $7.94/BOE, compared to $7.88/BOE in 2019. Cash G&A expenses in 2020 were $1.35/BOE, compared to $1.32/BOE in 2019.

●

Exploration and development capital spending totaled $291.4 million in 2020, below our capital budget guidance of $295 million. We paid $26.7 million in dividends in 2020.

●

We ended the year with total debt net of cash of $376.0 million, a decrease from $455.0 million in 2019, and we were undrawn on our US$600 million unsecured bank credit facility. At December 31, 2020, our net debt to adjusted funds flow ratio was 1.0x.

Reserves Highlights

●

Total proved plus probable (“2P”) reserves were 424.4 MMBOE at year end 2020, 4% lower than year end 2019.

●

We replaced 50% of our total 2020 production, adding 16.7 MMBOE of 2P reserves (including technical revisions and economic factors). In North Dakota, we replaced 69% of our 2020 production, adding 11.3 MMBOE of 2P reserves.

●

Excluding economic factors, we replaced 89% of our total 2020 production, adding 29.2 MMBOE of 2P reserves. In North Dakota, we replaced 119% of our 2020 production excluding economic factors, adding 19.4 MMBOE of 2P reserves. Economic factors are reserves revisions due to the significant reduction in year-over-year forecast prices.

●

F&D costs were $26.51/BOE for proved developed producing (“PDP”) reserves, $6.78/BOE for proved reserves, and $6.50/BOE for 2P reserves, including future development costs (“FDC”).

●

Finding, development and acquisition (“FD&A”) costs were $6.97/BOE for proved reserves and $6.74/BOE for 2P reserves, including FDC.

ENERPLUS 2020 FINANCIAL SUMMARY 3

MD&A

Exhibit 99.3

Management’s Discussion and Analysis (“MD&A”)

The following discussion and analysis of financial results is dated February 18, 2021 and is to be read in conjunction with the audited Consolidated Financial Statements (the “Financial Statements”) of Enerplus Corporation (“Enerplus” or the “Company”), as at December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018.

The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward-Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”). See “Non-GAAP Measures” at the end of this MD&A for further information.

BASIS OF PRESENTATION

The Financial Statements and notes have been prepared in accordance with U.S. GAAP. All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included with the Financial Statements. Certain prior period amounts have been restated to conform with current period presentation.

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and crude oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcfe. The BOE and Mcfe rates are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1 or 0.167:1, as applicable, utilizing a conversion on this basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are presented on a Company interest basis, being the Company’s working interest share before deduction of any royalties paid to others, plus the Company’s royalty interests, unless otherwise stated. Company interest is not a term defined in Canadian National Instrument 51-101– Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and may not be comparable to information produced by other entities. All reserves information presented herein has been prepared in accordance with NI 51-101 and is presented at December 31, 2020 unless otherwise stated.

All references to “liquids” in this MD&A include light and medium oil, heavy oil and tight oil (all together referred to as “crude oil”) and natural gas liquids on a combined basis. All references to “natural gas” in this MD&A include conventional natural gas and shale gas.

In accordance with U.S. GAAP, crude oil and natural gas sales are presented net of royalties in the Financial Statements. Under International Financial Reporting Standards, industry standard is to present crude oil and natural gas sales before deduction of royalties and as such this MD&A presents production, crude oil and natural gas sales, and BOE measures before deduction of royalties to remain comparable with our Canadian peers.

Unless otherwise expressly stated, information presented in this MD&A does not give effect to the proposed acquisition (the "Bruin Acquisition") by Enerplus Resources (USA) Corporation, an indirect wholly-owned subsidiary of the Company, of all of the equity interests of Bruin E&P HoldCo, LLC ("Bruin") from Bruin Purchaser LLC pursuant to a membership interest purchase and sale agreement dated as of January 25, 2021 (the "Purchase Agreement").

4 ENERPLUS 2020 FINANCIAL SUMMARY

The following table provides a reconciliation of our production volumes:


		Year ended December 31,
Average Daily Production Volumes	2020		2019		2018
Company interest production volumes
Light and medium oil (bbls/day)		3,277		3,908		4,287
Heavy oil (bbls/day)		3,901		4,717		4,995
Tight oil (bbls/day)		38,243		41,079		36,142
Total crude oil (bbls/day)		45,421		49,704		45,424

Natural gas liquids (bbls/day)		5,633		4,929		4,486

Conventional natural gas (Mcf/day)		12,314		23,400		27,159
Shale gas (Mcf/day)		225,543		255,051		232,678
Total natural gas (Mcf/day)		237,857		278,451		259,837
Company interest production volumes (BOE/day)		90,697		101,042		93,216

Royalty volumes
Light and medium oil (bbls/day)		676		944		957
Heavy oil (bbls/day)		477		969		916
Tight oil (bbls/day)		7,587		8,121		7,181
Total crude oil (bbls/day)		8,740		10,034		9,054

Natural gas liquids (bbls/day)		1,134		977		951

Conventional natural gas (Mcf/day)		898		2,080		2,588
Shale gas (Mcf/day)		45,945		50,790		46,335
Total natural gas (Mcf/day)		46,843		52,870		48,923
Royalty volumes (BOE/day)		17,681		19,823		18,159

Net production volumes
Light and medium oil (bbls/day)		2,601		2,964		3,330
Heavy oil (bbls/day)		3,424		3,748		4,079
Tight oil (bbls/day)		30,656		32,958		28,961
Total crude oil (bbls/day)		36,681		39,670		36,370

Natural gas liquids (bbls/day)		4,499		3,952		3,535

Conventional natural gas (Mcf/day)		11,416		21,320		24,571
Shale gas (Mcf/day)		179,598		204,261		186,343
Total natural gas (Mcf/day)		191,014		225,581		210,914
Net production volumes (BOE/day)		73,016		81,219		75,057

2020 FOURTH QUARTER OVERVIEW

Fourth quarter production averaged 86,244 BOE/day, at the high end of our fourth quarter production guidance range of 84,000 – 87,000 BOE/day and a decrease compared to third quarter 2020 production of 91,022 BOE/day. Crude oil and natural gas liquids production averaged 49,195 bbls/day compared to the third quarter average of 52,539 bbls/day and exceeded our fourth quarter liquids production guidance range of 47,000 – 49,000 bbls/day. Our fourth quarter capital spending was $52.4 million, bringing total 2020 capital spending to $291.4 million, below our guidance of $295 million.

We reported a net loss of $204.2 million in the fourth quarter compared to a net loss of $112.8 million in the third quarter of 2020. The increase in net loss was primarily the result of a $311.2 million non-cash PP&E impairment recorded in the fourth quarter compared to a $256.8 million PP&E impairment in the third quarter, both as a result of the low commodity price environment and the requirement to use SEC twelve month trailing prices to test for impairment.

Fourth quarter cash flow from operating activities decreased to $96.1 million from $137.0 million in the third quarter of 2020 primarily due to a decrease in non-cash operating working capital of $8.9 million during the fourth quarter, compared to a change of $55.8 million in the third quarter. Fourth quarter adjusted funds flow increased to $91.9 million, from $83.1 million during the third quarter, largely due to a $5.0 million increase in realized cash gains on commodity derivative instruments during the fourth quarter.

ENERPLUS 2020 FINANCIAL SUMMARY 5

Selected Fourth Quarter Canadian and U.S. Financial Results


	Three months ended						Three months ended
	December 31, 2020						December 31, 2019
($ millions, except per unit amounts)	Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes⁽¹⁾
Light and medium oil (bbls/day)		3,192		—		3,192		3,560		—		3,560
Heavy oil (bbls/day)		4,216		—		4,216		4,587		—		4,587
Tight oil (bbls/day)		—		35,997		35,997		—		46,197		46,197
Total crude oil (bbls/day)		7,408		35,997		43,405		8,147		46,197		54,344

Natural gas liquids (bbls/day)		580		5,210		5,790		797		4,705		5,502

Conventional natural gas (Mcf/day)		10,381		—		10,381		21,379		—		21,379
Shale gas (Mcf/day)		146		211,766		211,912		285		263,873		264,158
Total natural gas (Mcf/day)		10,527		211,766		222,293		21,664		263,873		285,537
Total average daily production (BOE/day)		9,743		76,501		86,244		12,555		94,881		107,436

Pricing⁽²⁾
Crude oil (per bbl)	$	41.75	$	49.22	$	47.95	$	55.69	$	69.26	$	67.23
Natural gas liquids (per bbl)		26.68		16.14		17.19		28.61		16.53		18.28
Natural gas (per Mcf)		3.25		1.98		2.04		2.53		2.50		2.50

Capital Expenditures
Capital spending	$	2.9	$	49.5	$	52.4	$	7.5	$	91.9	$	99.4
Acquisitions		0.5		1.6		2.1		3.1		3.0		6.1
Divestments		—		—		—		0.3		—		0.3

Netback⁽³⁾ Before Hedging
Crude oil and natural gas sales	$	33.4	$	209.3	$	242.7	$	49.5	$	362.1	$	411.6
Royalties		(4.7)		(43.0)		(47.7)		(11.3)		(73.3)		(84.6)
Production taxes		(0.5)		(12.7)		(13.2)		(0.7)		(22.8)		(23.5)
Operating expenses		(14.0)		(51.1)		(65.1)		(18.2)		(61.3)		(79.5)
Transportation costs		(2.4)		(28.4)		(30.8)		(2.1)		(35.7)		(37.8)
Netback before hedging	$	11.8	$	74.1	$	85.9	$	17.2	$	169.0	$	186.2

Other Expenses
Asset impairment	$	33.5	$	277.7	$	311.2	$	—	$	—	$	—
Goodwill impairment		—		—		—		451.1		—		451.1
Commodity derivative instruments loss/(gain)		12.5		—		12.5		28.8		—		28.8
General and administrative expense⁽⁴⁾		3.3		13.2		16.5		8.7		10.1		18.8
Current income tax recovery		—		—		—		—		(14.0)		(14.0)

(1)	Company interest volumes.

(2)	Before transportation costs, royalties and the effects of commodity derivative instruments.

(3)	See “Non-GAAP Measures” section in this MD&A.

(4)	Includes share-based compensation.

Comparing the fourth quarter of 2020 with the same period in 2019:

●

Average daily production was 86,244 BOE/day, a decrease of 20% from 107,436 BOE/day. The decrease in crude oil production was a result of the suspension of our operated North Dakota drilling and completions program early in 2020 as a result of weak commodity prices. Natural gas production decreased due to limited capital activity in the Marcellus and our decision to shut-in, abandon and reclaim our Canadian natural gas property in Tommy Lakes during the first quarter of 2020. These impacts were partially offset by an increase in natural gas liquids production over the same period due to an increase in natural gas liquids recoveries.

●	Our crude oil and natural gas liquids production accounted for 57% of our total production mix in the fourth quarter of 2020, compared to 56% in 2019.

●

Capital spending decreased to $52.4 million compared to $99.4 million in the fourth quarter of 2019 due to the suspension of our operated North Dakota drilling and completions program early in 2020. The majority of our capital investment in the fourth quarter of 2020 was focused on our U.S. crude oil properties, including the completion of four drilled uncompleted wells and approximately three net-operated wells.

●	Operating expenses decreased to $65.1 million ($8.20/BOE) compared to $79.5 million ($8.05/BOE) in the fourth quarter of 2019. Operating costs increased on a per BOE basis due to lower production.

6 ENERPLUS 2020 FINANCIAL SUMMARY

●	Cash general and administrative (“G&A”) expenses decreased to $11.6 million compared to $13.3 million in 2019, however increased on a per BOE basis totaling $1.46/BOE in the fourth quarter of 2020, compared to $1.34/BOE in the same period of 2019 due to lower production.

●

During the fourth quarter of 2020, our Bakken crude oil price differential widened to US$4.82/bbl below WTI, compared to US$4.40/bbl below WTI for the same period in 2019, due to much narrower Brent-WTI differentials. Our fourth quarter 2020 Marcellus natural gas differential was US$1.07/Mcf below NYMEX, compared to US$0.63/Mcf below NYMEX during the same period in 2019. Regional pricing in the Marcellus was particularly weak from September to November 2020 due to nearly full regional storage combined with low demand due to mild weather.

●

We reported a net loss of $204.2 million in the fourth quarter of 2020 compared to net loss of $429.1 million in the fourth quarter of 2019. Our net loss decreased by $224.9 million due to lower non-cash impairment charges, with a non-cash PP&E impairment of $311.2 million recorded in the fourth quarter of 2020 compared to a non-cash goodwill impairment of $451.1 million recorded in the fourth quarter of 2019. The decrease in the net loss was also due to a $116.7 million deferred income tax recovery in the fourth quarter of 2020 compared to an expense of $31.8 million in the same period in 2019.

●

Cash flow from operating activities and adjusted funds flow decreased to $96.1 million and $91.9 million, respectively, compared to $188.5 million and $178.9 million, respectively, in the fourth quarter of 2019. The decreases were primarily the result of a $132.0 million decrease in crude oil and natural gas sales, net of royalties, partially offset by $24.7 million in realized cash gains on commodity derivative instruments in the fourth quarter of 2020.

●	Net debt to adjusted funds flow increased to 1.0x in the fourth quarter of 2020 compared to 0.6x in the fourth quarter of 2019.

2020 OVERVIEW


Summary of Guidance and Results	Revised 2020 Guidance	2020 Results
Capital spending ($ millions)	$295	$291
Average annual production (BOE/day)	90,000 - 91,000	90,697
Average annual crude oil and natural gas liquids production (bbls/day)	50,500 - 51,000	51,054
Fourth quarter average production (BOE/day)	84,000 - 87,000	86,244
Fourth quarter average crude oil and natural gas liquids production (bbls/day)	47,000 - 49,000	49,195
Average royalty and production tax rate (% of gross sales, before transportation)	26%	26%
Operating expenses (per BOE)	$8.00	$7.94
Transportation costs (per BOE)	$4.00	$3.99
Cash G&A expenses (per BOE)	$1.35	$1.35

Differential/Basis Outlook and Results⁽¹⁾
Average U.S. Bakken crude oil differential (compared to WTI crude oil)	US$(5.00)/bbl	US$(4.96)/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)	US$(0.60)/Mcf	US$(0.65)/Mcf

(1)	Excludes transportation costs

The coronavirus (“COVID-19”) pandemic had a major impact on the global economy in 2020 and posed significant challenges for our industry. In response to a dramatic decline in crude oil demand and historically low prices during the second quarter of 2020, we temporarily curtailed certain wells across our crude oil and natural gas liquids properties and suspended our operated drilling and completions activity in North Dakota. In response to strengthening prices, our previously curtailed production was fully restored during the third quarter and we completed four net operated wells in North Dakota and approximately three net non-operated wells during the fourth quarter. Although markets remain volatile and the timing of a full economic recovery remains uncertain, crude oil prices continue to improve as supply moderates and demand levels begin to recover. We remained committed to preserving our strong financial position through a focus on reducing costs, maintaining capital discipline and delivering strong operational performance.

Our 2020 annual average production was 90,697 BOE/day with crude oil and natural gas liquids volumes of 51,054 bbls/day, meeting our revised production guidance target of 90,000 – 91,000 BOE/day and exceeding our revised crude oil and natural gas liquids production guidance of 50,500 – 51,000 bbls/day. Our capital spending for the year totaled $291.4 million, below our revised guidance of $295 million. The majority of our capital was directed to our U.S. crude oil properties, with approximately 80% of total spending focused on our North Dakota and Colorado properties.

Our Bakken sales price differentials widened in comparison to the prior year averaging US$4.96/bbl below WTI, in line with our guidance of US$5.00/bbl below WTI. Bakken differentials were negatively impacted by the significant benchmark oil price volatility and the narrowing of the Brent-WTI price differentials in 2020. Our Marcellus differential of US$0.65/Mcf below NYMEX was slightly higher than our revised differential outlook of US$0.60/Mcf below NYMEX and wider than our 2019 differential of US$0.39/Mcf below NYMEX. Regional pricing in the Marcellus was particularly weak from September to November of 2020 as a result of nearly full regional storage combined with low demand due to mild weather.

ENERPLUS 2020 FINANCIAL SUMMARY 7

Operating expenses were $7.94/BOE, below our revised guidance of $8.00/BOE. Cash G&A expenses were $1.35/BOE, in line with our revised guidance of $1.35/BOE.

Cash flow from operations and adjusted funds flow decreased to $446.4 million and $358.2 million, respectively, from $694.2 million and $709.0 million, respectively, in 2019. The decrease was mainly due to a $517.6 million reduction in crude oil and natural gas sales, net of royalties, due to a decrease in realized commodity prices and lower production compared to 2019. This was partially offset by a $115.6 million increase in realized commodity derivative instrument gains.

We reported a net loss of $923.4 million in 2020, an increase from a net loss of $259.7 million in 2019. Our net loss was impacted by non-cash impairments of $994.8 million on PP&E and $202.8 million on goodwill as a result of low commodity prices. These reductions were partially offset by a total income tax recovery of $260.8 million in 2020 compared to an expense of $47.9 million in 2019.

Total debt net of cash at December 31, 2020 was $376.0 million, comprised of $490.4 million of senior notes less $114.5 million in cash. At December 31, 2020, we were undrawn on our US$600 million senior unsecured bank credit facility and had a net debt to adjusted funds flow ratio of 1.0x.

2021 OUTLOOK

On January 25, 2021, we entered into the Purchase Agreement to acquire all the equity interests of Bruin, a pure play Williston Basin private company, for total cash consideration of US$465 million, with no assumption of debt and subject to certain adjustments. On the same date, we entered into a binding commitment letter for a new three-year senior unsecured US$400 million term facility (the "Term Facility") to be fully drawn down on the closing date of the Bruin Acquisition to pay for a portion of the purchase price. We intend to fund the remaining portion of the purchase price with net proceeds from a $132.3 million bought deal equity financing, which we completed on February 3, 2021. Closing of the Bruin Acquisition is expected to occur early in March 2021 and is subject to customary closing conditions and purchase price adjustments including those related to the fair value of Bruin’s commodity hedge contracts. Bruin’s current production is approximately 24,000 BOE/day (72% tight oil, 14% natural gas liquids, and 14% natural gas). Refer to the material change report dated January 29, 2021 in connection with the Bruin Acquisition and available under the Enerplus’ SEDAR profile at www.sedar.com and on the Enerplus’ EDGAR profile under Form 6-K at www.sec.gov.

We expect that the Bruin Acquisition will further support our 2021 strategy of creating value for our shareholders through strong free cash flow generation and disciplined returns-oriented focus, while maintaining balance sheet strength. We expect our net debt to trailing adjusted funds flow ratio to be approximately 1.0x at year end 2021 based on WTI of US$55.00/bbl and NYMEX of US$3.00/Mcf. We expect to be undrawn on our US$600 million credit facility upon the closing of the Bruin Acquisition.

Our 2021 production volumes are expected to average 103,500 – 108,500 BOE/day, including 63,000 – 67,000 bbl/day of crude oil and natural gas liquids production, assuming the Bruin Acquisition closes in early March 2021 and a ten-month contribution from Bruin’s assets. Based on the same assumption, we expect our capital budget range for 2021 is between $335 million and $385 million, with the majority directed to our North Dakota assets.

We expect our Bakken sales price differential to narrow to US$3.25/bbl below WTI in 2021, assuming the Dakota Access Pipeline (“DAPL”) continues to operate, an improvement from our 2020 differential of US$4.96/bbl below WTI. The expected improvement is due to declining regional production leading to increased pipeline egress. In the Marcellus, we have a differential outlook of US$0.55/Mcf below NYMEX in 2021.

To support our 2021 capital program, and assuming the closing of the Bruin Acquisition, we have hedged approximately 21,500 bbls/day and 17,000 bbls/day, respectively, of our expected crude oil production for 2021 and 2022. For natural gas, we have hedged 60,000 Mcf/day for March 2021 and 100,000 Mcf/day for April 1 to October 31, 2021.

We plan to provide additional 2021 guidance upon the closing of the Bruin Acquisition.

8 ENERPLUS 2020 FINANCIAL SUMMARY

RESULTS OF OPERATIONS

Production


Average Daily Production Volumes	2020	2019	2018
Light and medium oil (bbls/day)	3,277	3,908	4,287
Heavy oil (bbls/day)	3,901	4,717	4,995
Tight oil (bbls/day)	38,243	41,079	36,142
Total crude oil (bbls/day)	45,421	49,704	45,424

Natural gas liquids (bbls/day)	5,633	4,929	4,486

Conventional natural gas (Mcf/day)	12,314	23,400	27,159
Shale gas (Mcf/day)	225,543	255,051	232,678
Total natural gas (Mcf/day)	237,857	278,451	259,837
Total daily sales (BOE/day)	90,697	101,042	93,216

Production in 2020 averaged 90,697 BOE/day, in line with our revised production guidance range of 90,000 – 91,000 BOE/day, and resulting in a 10% decrease compared to 2019 production of 101,042 BOE/day. Crude oil and natural gas liquids production in 2020 averaged 51,054 bbls/day, exceeding our revised guidance range of 50,500 – 51,500 bbls/day. Compared to 2019, our crude oil and natural gas liquids production decreased 7% due to the temporary curtailment of certain crude oil and natural gas liquids properties and the suspension of all operated drilling and completion activity in North Dakota during the second quarter of 2020, in response to the significant decline in crude oil prices.

Our U.S. production volumes decreased by 8% compared to 2019 and our U.S. crude oil and natural gas liquids production decreased by 4% to 43,248 bbls/day, primarily due to temporary production curtailments and the suspension of our operated North Dakota drilling and completions program early in 2020 due to weak commodity prices. Our U.S. natural gas production decreased by 12% due to limited capital activity in the Marcellus.

Canadian production volumes decreased by 27% compared to the prior year, due to our decision to shut-in, abandon and reclaim our Canadian natural gas property in Tommy Lakes during the first quarter of 2020.

Our crude oil and natural gas liquids production accounted for 56% of our total average daily production in 2020, an increase from 54% in 2019.

Production for 2019 increased by 7,826 BOE/day to 101,042 BOE/day, compared to 2018. The 8% increase was largely due to an increase to the 2019 capital spending program and additional wells brought on-stream in North Dakota and Colorado. During the same period, U.S. natural gas production increased 10% due to strong well performance in the Marcellus in 2019.

2021 Guidance

We expect annual average production for 2021 of 103,500 – 108,500 BOE/day, including 63,000 – 67,000 bbls/day of crude oil and natural gas liquids production, assuming the closing of the Bruin Acquisition in early March 2021 and a ten month contribution from Bruin’s assets in 2021.

ENERPLUS 2020 FINANCIAL SUMMARY 9

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, cash flow from operating activities, adjusted funds flow and financial condition. The following table summarizes our average selling prices, benchmark prices and differentials:


Pricing (average for the period)	2020		2019		2018
Benchmarks
WTI crude oil (US$/bbl)	$	39.40	$	57.03	$	64.77
Brent (ICE) crude oil (US$/bbl)		43.21		64.18		71.53
NYMEX natural gas – last day (US$/Mcf)		2.08		2.63		3.09
US/CDN average exchange rate		1.34		1.33		1.30
US/CDN period end exchange rate		1.27		1.30		1.36

Enerplus selling price⁽¹⁾
Crude oil ($/bbl)	$	44.35	$	68.98	$	74.59
Natural gas liquids ($/bbl)		10.29		15.19		28.31
Natural gas ($/Mcf)		1.87		2.87		3.42

Average benchmark differentials
Bakken DAPL - WTI (US$/bbl)	$	(4.27)	$	(3.46)	$	(3.73)
Brent (ICE) - WTI (US$/bbl)		3.81		7.15		6.77
MSW Edmonton – WTI (US$/bbl)		(5.33)		(4.88)		(11.12)
WCS Hardisty – WTI (US$/bbl)		(12.60)		(12.76)		(26.31)
Transco Leidy monthly – NYMEX (US$/Mcf)		(0.72)		(0.46)		(0.64)
Transco Z6 Non-New York monthly – NYMEX (US$/Mcf)		0.34		0.23		0.75

Enerplus realized differentials⁽¹⁾⁽²⁾
Bakken crude oil – WTI (US$/bbl)	$	(4.96)	$	(3.61)	$	(3.78)
Marcellus natural gas – NYMEX (US$/Mcf)		(0.65)		(0.39)		(0.43)
Canada crude oil – WTI (US$/bbl)		(13.04)		(12.11)		(21.83)

(1)	Excluding transportation costs, royalties and the effects of commodity derivative instruments.

(2)	Based on a weighted average differential for the period.

CRUDE OIL AND NATURAL GAS LIQUIDS

Benchmark WTI prices averaged US$39.40/bbl in 2020, a 31% decrease from 2019, largely due to the COVID-19 pandemic and the resulting reduction in crude oil demand due to restrictions on mobility and travel. WTI prices fell sharply in the second quarter of 2020, at one point reaching negative values in April, which resulted in production curtailments across North America that helped balance the market further throughout the year. The Organization of Petroleum Exporting Countries (“OPEC”) lowered its production quotas in response to the pandemic in the spring. Crude oil markets recovered through the second half of the year as global economies stabilized and demand for crude oil began to recover. This resulted in lower global crude oil storage and higher WTI prices at the end of the year. Our 2020 realized crude oil price averaged $44.35/bbl, representing a 36% decrease compared to 2019 and a 31% decrease in benchmark WTI prices as a result of wider Bakken crude oil differentials compared to the previous year.

Our Bakken sales price differentials weakened in 2020 compared to 2019, averaging US$4.96/bbl below WTI, in line with our guidance of US$5.00/bbl below WTI. Bakken prices were volatile in the second quarter of 2020 due to significant benchmark oil price fluctuations. Additionally, weakness in U.S. Gulf Coast grades and a narrow Brent-WTI differential reduced our realized pricing on physical sales that were linked to these markets. We expect our realized Bakken differential to average US$3.25/bbl below WTI in 2021, assuming DAPL continues to operate.

Canadian crude oil differentials weakened slightly in 2020 compared to the prior year. Differentials were weaker in the first quarter of 2020 prior to industry wide production curtailments. Differentials narrowed after April and throughout the remainder of year as spare capacity increased on export pipelines as a result of lower production levels.

We realized an average price of $10.29/bbl on our natural gas liquids production in 2020, a 32% decrease compared to 2019 and in line with changes to benchmark oil prices. A significant portion of our natural gas liquid sales are linked to WTI prices, particularly condensate and butane.

10 ENERPLUS 2020 FINANCIAL SUMMARY

NATURAL GAS

Our realized natural gas price averaged $1.87/Mcf in 2020, a 35% decrease from 2019. This decrease was greater than the 21% decline in benchmark natural gas prices due to significantly weaker gas prices in the Marcellus in 2020.

In the Marcellus, we realized an average sales price differential of US$0.65/Mcf below NYMEX, slightly higher than our revised guidance of $0.60/Mcf below NYMEX for the year and wider compared to our 2019 realized sales price differential of $0.39/Mcf. The Transco Leidy monthly benchmark differential averaged US$0.72/Mcf below NYMEX for 2020, which was weaker than 2019 as the local market suffered from high storage levels and a lack of weather-induced demand, particularly in the shoulder months of September and October. At the same time, NYMEX Natural Gas prices at Henry Hub were significantly stronger due to the much improved supply and demand outlook for the upcoming winter. Transco Z6 Non-New York Leidy monthly benchmark differentials averaged US$0.34/Mcf above NYMEX for 2020, a slight improvement over the full 2019 differential. We expect our Marcellus differential to average US$0.55/Mcf below NYMEX in 2021.

Monthly Crude Oil Prices

Monthly Natural Gas Prices

ENERPLUS 2020 FINANCIAL SUMMARY 11

FOREIGN EXCHANGE

Our crude oil and natural gas sales are impacted by foreign exchange fluctuations as the majority of our sales are based on U.S. dollar denominated benchmark indices. A stronger Canadian dollar decreases the amount of our realized sales, as well as the amount of our U.S. denominated costs, such as capital, the interest on our U.S. denominated debt, and the value of our outstanding U.S. senior notes.

The Canadian dollar weakened during 2020 in response to lower commodity prices as a result of the global excess supply of crude oil and the decreased demand impact of the COVID-19 pandemic. The USD/CDN exchange rate peaked at 1.45 USD/CDN in March and remained volatile for the remainder of the year, resulting in an average exchange rate of 1.34 USD/CDN during 2020 compared to an average of 1.33 in 2019. The Canadian dollar strengthened at the end of the 2020 to close at 1.27 USD/CDN compared to 1.30 USD/CDN at December 31, 2019.

Monthly USD/CDN Exchange Rate

Price Risk Management

We have a price risk management program that considers our overall financial position and the economics of our capital expenditures.

As of February 18, 2021, we have hedged approximately 21,500 bbls/day and 17,000 bbls/day, respectively, of our expected crude oil production for 2021 and 2022. Our crude oil hedges are predominantly three way collars. The three way collars provide us with exposure to significant upward price moves; however, the sold put effectively limits the amount of downside protection we have to the difference between the strike price of the purchased and sold puts. For natural gas, we have hedged 60,000 Mcf/day for March 2021 and 100,000 Mcf/day for April 1 to October 31, 2021. Overall, we expect our crude oil and natural gas related hedging contracts to protect a significant portion of our cash flow from operating activities and adjusted funds flow in both 2021 and 2022.

12 ENERPLUS 2020 FINANCIAL SUMMARY

The following is a summary of Enerplus’ financial contracts in place at February 18, 2021:


	WTI Crude Oil (US$/bbl)⁽¹⁾				NYMEX Natural Gas (US$/Mcf)
	Jan 1, 2021 –	Apr 1, 2021-	Jul 1, 2021 -	Jan 1 ,2022 -	Mar 1, 2021-	Apr 1, 2021 -
	Mar 31, 2021	Jun 30, 2021	Dec 31, 2021	Dec 31, 2022	Mar 31, 2021	Oct 31, 2021
Swaps
Volume (bbls/d or Mcf/d)	5,000	-	-	-	60,000	60,000
Sold Swaps	$ 45.55	-	-	-	$ 3.16	$ 2.90

Three Way Collars
Volume (bbls/d or Mcf/d)	15,000	20,000	23,000	17,000	-	40,000
Sold Puts	$ 32.00	$ 32.00	$ 36.39	$ 40.00	-	$ 2.15
Purchased Puts	$ 40.53	$ 40.90	$ 46.39	$ 50.00	-	$ 2.75
Sold Calls	$ 50.29	$ 50.72	$ 56.70	$ 57.91	-	$ 3.25

(1)	The total average deferred premium spent on our outstanding hedges is US$0.80/bbl from January 1, 2021 – December 31, 2021 and US$1.50/bbl from January 1, 2022 – December 31, 2022.

As of February 18, 2021, the following is a summary of Bruin’s financial contracts, which Enerplus will assume upon the close of the Bruin Acquisition.


	WTI Crude Oil (US$/bbl)⁽¹⁾⁽²⁾
	Mar 1, 2021 -	Jan 1, 2022 -	Jan 1, 2023 -	Nov 1, 2023-
	Dec 31, 2021	Dec 31, 2022	Oct 31, 2023	Dec 31, 2023
Swaps
Volume (bbls/d)	9,000	3,900	250	-
Sold Swaps	$ 42.35	$ 42.38	$ 42.10	-

Collars
Volume (bbls/d)	-	-	2,000	2,000
Purchased Puts	-	-	$ 5.00	$ 5.00
Sold Calls	-	-	$ 75.00	$ 75.00

(1)	Transactions with a common term have been aggregated and presented at weighted average prices and volumes.

(2)

Upon close of the Bruin Acquisition, these hedges will be recorded at fair value on the Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired hedges will be recorded in the Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets, respectively, to reflect changes in WTI prices from the date of the close of the Bruin Acquisition.

ACCOUNTING FOR PRICE RISK MANAGEMENT


Commodity Derivative Instruments Gains/(Losses)
($ millions)	2020		2019		2018
Cash gains/(losses):
Crude oil	$	131.0	$	(12.1)	$	(52.0)
Natural gas		—		27.4		16.2
Total cash gains/(losses)	$	131.0	$	15.3	$	(35.8)

Non-cash gains/(losses):
Crude oil	$	(25.7)	$	(70.5)	$	114.8
Natural gas		3.5		(10.9)		9.2
Total non-cash gains/(losses)	$	(22.2)	$	(81.4)	$	124.0
Total commodity derivative instruments gains/(losses)	$	108.8	$	(66.1)	$	88.2


(Per BOE)	2020		2019		2018
Total cash gains/(losses)	$	3.95	$	0.42	$	(1.05)
Total non-cash gains/(losses)		(0.66)		(2.21)		3.64
Total commodity derivative instruments gains/(losses)	$	3.29	$	(1.79)	$	2.59

During 2020, we realized cash gains of $131.0 million on crude oil contracts and no cash gains or losses on our natural gas contracts, compared to cash losses of $12.1 million on crude oil contracts and cash gains of $27.4 million on our natural gas contracts in 2019. Cash gains in 2020 on crude oil contracts were primarily due to prices falling below the swap level as well as the net effect of benchmark prices below the put levels on both our put spreads and three way collars.

ENERPLUS 2020 FINANCIAL SUMMARY 13

As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. The fair value of our crude oil contracts at December 31, 2020 was a net liability position of $15.6 million (December 31, 2019 – net asset position of $10.1 million). The fair value of our natural gas contracts at December 31, 2020 was in a net asset position of $3.5 million (December 31, 2019 – no contracts outstanding). The change in fair value of our crude oil and natural gas contracts represented losses of $25.7 million and gains of $3.5 million, respectively, during 2020 and losses of $70.5 million and $10.9 million, respectively, during 2019.

Revenues


($ millions)	2020		2019		2018
Crude oil and natural gas sales	$	923.5	$	1,572.9	$	1,610.9
Royalties		(186.3)		(318.1)		(318.2)
Crude oil and natural gas sales, net of royalties	$	737.2	$	1,254.8	$	1,292.7

Crude oil and natural gas sales revenue for 2020 totaled $923.5 million, a decrease of 41% from $1,572.9 million in 2019. The decrease in revenue was a result of lower commodity prices and a decrease in production volumes.

Crude oil and natural gas sales revenue for 2019 totaled $1,572.9 million, a decrease of 2% from $1,610.9 million in 2018. The decrease in revenue was a result of lower commodity prices, which more than offset the increase in production volumes.

Royalties and Production Taxes


($ millions, except per BOE amounts)	2020		2019		2018
Royalties	$	186.3	$	318.1	$	318.2
Per BOE	$	5.61	$	8.63	$	9.35

Production taxes	$	49.9	$	83.1	$	87.3
Per BOE	$	1.51	$	2.25	$	2.57
Royalties and production taxes	$	236.2	$	401.2	$	405.5
Per BOE	$	7.12	$	10.88	$	11.92

Royalties and production taxes (% of crude oil and natural gas sales)		25.6%		25.5%		25.2%

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees and freehold mineral taxes. A large percentage of our production is from U.S. properties where royalty rates are generally higher than in Canada and less sensitive to commodity price levels.

Royalties and production taxes were in line with our guidance of 26% for 2020, averaging 25.6% of crude oil and natural gas sales, before transportation. Royalties and production taxes of $236.2 million in 2020, decreased in comparison to prior years due to lower realized commodity prices and production volumes. Royalties and production taxes of $401.2 million in 2019 were consistent with 2018, but decreased on a per BOE basis due to lower realized commodity prices.

Operating Expenses


($ millions, except per BOE amounts)	2020		2019		2018
Operating expenses	$	263.6	$	290.8	$	238.3
Per BOE	$	7.94	$	7.88	$	7.00

Operating expenses for 2020 were $263.6 million or $7.94/BOE, beating our revised guidance of $8.00/BOE and representing a decrease of $27.2 million or an increase of $0.06/BOE from the prior year. The decrease was largely due to lower fluid handling costs associated with lower production volumes. This was partially offset by additional well service activity and repairs and maintenance during the third quarter of 2020, as previously curtailed production was restored.

Operating expenses for 2019 were $290.8 million or $7.88/BOE, representing an increase of $52.5 million or $0.88/BOE from 2018. The increase was mainly attributable to additional well service activity, higher fluid handling costs and gas processing charges related to our North Dakota asset.

14 ENERPLUS 2020 FINANCIAL SUMMARY

Transportation Costs


($ millions, except per BOE amounts)	2020		2019		2018
Transportation costs	$	132.4	$	144.9	$	123.5
Per BOE	$	3.99	$	3.93	$	3.63

Transportation costs in 2020 were in line with our revised guidance of $4.00/BOE, averaging $3.99/BOE or $132.4 million, compared to $3.93/BOE or $144.9 million in 2019. The reduction in transportation costs was primarily a result of lower U.S. production with higher associated transportation costs compared to the same period in the prior year, partly due to price related production curtailments in the second quarter of 2020. On a per BOE basis, transportation costs were in line with the prior year.

Transportation costs in 2019 were $3.93/BOE, an increase from $3.63/BOE in 2018. The overall increase in transportation costs were due to additional crude oil firm transportation commitments that provide access to sell a portion of our production at U.S. Gulf Coast or Brent pricing that commenced March 1, 2019.

Netbacks

The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.


	Year ended December 31, 2020
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			56,055 BOE/day		207,855 Mcfe/day		90,697 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	37.78	$	1.95	$	27.82
Royalties and production taxes			(10.07)		(0.39)		(7.12)
Operating expenses			(11.75)		(0.29)		(7.94)
Transportation costs			(2.90)		(0.96)		(3.99)
Netback before hedging		$	13.06	$	0.31	$	8.77
Cash gains/(losses)			6.38		—		3.95
Netback after hedging		$	19.44	$	0.31	$	12.72
Netback before hedging ($ millions)		$	268.0	$	23.3	$	291.3
Netback after hedging ($ millions)		$	399.0	$	23.3	$	422.3


	Year ended December 31, 2019
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			58,679 BOE/day		254,177 Mcfe/day		101,042 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	60.60	$	2.97	$	42.65
Royalties and production taxes			(16.30)		(0.56)		(10.88)
Operating expenses			(12.23)		(0.31)		(7.88)
Transportation costs			(2.97)		(0.88)		(3.93)
Netback before hedging		$	29.10	$	1.22	$	19.96
Cash gains/(losses)			(0.57)		0.30		0.42
Netback after hedging		$	28.53	$	1.52	$	20.38
Netback before hedging ($ millions)		$	623.3	$	112.7	$	736.0
Netback after hedging ($ millions)		$	611.1	$	140.3	$	751.4

(1)	See “Non-GAAP Measures” in this MD&A.

ENERPLUS 2020 FINANCIAL SUMMARY 15


	Year ended December 31, 2018
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			53,294 BOE/day		239,532 Mcfe/day		93,216 BOE/day
Netback⁽¹⁾ $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	67.43	$	3.42	$	47.35
Royalties and production taxes			(17.90)		(0.65)		(11.92)
Operating expenses			(10.54)		(0.38)		(7.00)
Transportation costs			(2.40)		(0.88)		(3.63)
Netback before hedging		$	36.59	$	1.51	$	24.80
Cash gains/(losses)			(2.67)		0.19		(1.05)
Netback after hedging		$	33.92	$	1.70	$	23.75
Netback before hedging ($ millions)		$	711.7	$	131.9	$	843.6
Netback after hedging ($ millions)		$	659.7	$	148.1	$	807.8

(1)	See “Non-GAAP Measures” in this MD&A.

As a result of the low commodity price environment, total netbacks before and after hedging decreased by 60% and 44%, respectively, in 2020 compared to 2019. Our price risk management program continued to provide adjusted funds flow protection, with realized cash gains on our crude oil derivative instruments partially offsetting the impact of lower realized pricing. During 2020, our crude oil properties accounted for 92% and 94% of our netback before and after hedging, respectively, compared to 85% and 81%, respectively, in 2019.

General and Administrative Expenses

Total G&A expenses include cash G&A expenses and share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”). See Note 11, Note 14 and Note 15 to the Financial Statements for further details.


($ millions)	2020		2019		2018
Cash:
G&A expense	$	44.9	$	48.8	$	50.0
Share-based compensation expense		(1.4)		0.7		0.1

Non-Cash:
Share-based compensation expense		13.0		22.3		25.9
Equity swap loss/(gain)		1.4		0.3		(0.2)
G&A expense/(recovery)		(0.3)		0.7		—
Total G&A expenses	$	57.6	$	72.8	$	75.8


(Per BOE)	2020		2019		2018
Cash:
G&A expense	$	1.35	$	1.32	$	1.47
Share-based compensation expense		(0.04)		0.02		0.01

Non-Cash:
Share-based compensation expense		0.39		0.61		0.76
Equity swap loss/(gain)		0.04		0.01		(0.01)
G&A expense/(recovery)		(0.01)		0.02		—
Total G&A expenses	$	1.73	$	1.98	$	2.23

Cash G&A expenses were $44.9 million, or $1.35/BOE, in 2020, meeting our revised guidance of $1.35/BOE and lower in comparison to our 2019 Cash G&A of $48.8 million, or $1.32/BOE. Cash G&A expenses were lower in 2020 in part due to government funding received related to the second quarter, at the height of the uncertainty brought on by the COVID-19 pandemic, which reimbursed qualifying Canadian employers for a portion of salaries paid. Cash G&A expenses were further lowered by cash compensation reductions for our Board of Directors, executives and employees in effect during a portion of 2020, and other non-salary cost saving initiatives.

During 2020, we reported a cash SBC recovery of $1.4 million due to the impact of a lower share price on our outstanding Director Deferred Share Units (“DSUs”) and Director Restricted Share Units (“RSUs”), compared to an expense of $0.7 million in 2019. We recorded a non-cash SBC expense of $13.0 million, or $0.39/BOE, in 2020, compared to an expense of $22.3 million, or $0.61/BOE, in 2019. The decrease in non-cash SBC in 2020 was a result of a lower multiplier on our Performance Share Units (“PSUs”) compared to 2019.

16 ENERPLUS 2020 FINANCIAL SUMMARY

Cash G&A expenses in 2019 were $48.8 million, or $1.32/BOE, a decrease from $50.0 million, or $1.47/BOE, in 2018, mostly due to an increase in our production over the period. Cash SBC expense was $0.7 million, or $0.02/BOE, in 2019 compared to an expense of $0.1 million, or $0.01/BOE, in 2018. We recorded non-cash SBC of $22.3 million, or $0.61/BOE in 2019 compared to $25.9 million, or $0.76/BOE, in 2018. The decrease in non-cash SBC in 2019 was a result of a lower multiplier on our PSUs compared to 2018.

We have hedged a portion of the outstanding cash-settled units under our LTI plans. We recorded a non-cash mark-to-market loss of $1.4 million on these hedges in 2020 (2019 – $0.3 million loss; 2018 – $0.2 million gain).

Interest Expense

Interest on our senior notes and bank credit facility for 2020 totaled $28.4 million, a decrease of 16% from $33.9 million in 2019. The decrease was due to the repayment of a portion of our 2009 and 2012 senior notes during the second quarter of 2020.

Interest on our senior notes and bank credit facility for 2019 of $33.9 million decreased compared to $36.8 million in 2018 due to the repayment of a portion of our 2009 senior notes and the bullet repayment of the full principal amount of our 2012 $30 million senior notes during 2019.

At December 31, 2020, we were undrawn on our US$600 million bank credit facility and our debt consisted of fixed interest rate senior notes with a weighted average interest rate of 4.4%. See Note 7 to the Financial Statements for further details on our outstanding notes.

Foreign Exchange


($ millions)	2020		2019		2018
Realized:
Foreign exchange loss/(gain) on settlements	$	0.6	$	(0.1)	$	0.5
Translation of U.S. dollar cash held in Canada loss/(gain)		(1.2)		8.8		(19.6)
Unrealized loss/(gain)		1.9		(34.1)		58.6
Total foreign exchange loss/(gain)	$	1.3	$	(25.4)	$	39.5
US/CDN average exchange rate		1.34		1.33		1.30
US/CDN period end exchange rate		1.27		1.30		1.36

We recorded a total foreign exchange loss of $1.3 million in 2020, compared to a gain of $25.4 million in 2019 and a loss of $39.5 million in 2018. Realized gains and losses relate primarily to day-to-day transactions recorded in foreign currencies and the translation of our U.S. dollar denominated cash held in Canada, while unrealized gains and losses are recorded on the translation of our U.S. dollar denominated bank debt and working capital held in Canada at each period-end.

Effective January 1, 2020, we have designated our outstanding senior notes as a net investment hedge related to our U.S. operations. As a result of the adoption of net investment hedge accounting, any unrealized foreign exchange gains and losses on the translation of this U.S. dollar denominated debt are included in Other Comprehensive Income/(Loss). At December 31, 2020, US$385.4 million of senior notes outstanding were designated as a net investment hedge. For the year ended December 31, 2020, Other Comprehensive Income/(Loss) included an unrealized gain of $2.2 million on our outstanding U.S. dollar denominated senior notes. For December 31, 2019 and 2018, the unrealized gains and losses recorded on the translation of our senior notes was included in Consolidated Net Income/(Loss). Comparing December 31, 2019 to December 31, 2018, the Canadian dollar strengthened relative to the U.S. dollar, resulting in an unrealized gain of $34.1 million. See Note 2(k) to the Financial Statements for further details.

Capital Investment


($ millions)	2020		2019		2018
Capital spending	$	291.4	$	618.9	$	593.9
Office capital		4.3		5.8		6.5
Line fill		—		5.1		—
Sub-total		295.7		629.8		600.4
Property and land acquisitions	$	10.1	$	24.4	$	25.8
Property divestments		(6.1)		(9.6)		(6.9)
Sub-total		4.0		14.8		18.9
Total⁽¹⁾	$	299.7	$	644.6	$	619.3

(1)	Excludes changes in non-cash investing working capital. See Note 18(b) of the Consolidated Financial Statements for additional information.

ENERPLUS 2020 FINANCIAL SUMMARY 17

2020

Capital spending in 2020 totaled $291.4 million, lower than our revised guidance of $295 million. In 2020, we spent $234.8 million on our U.S. crude oil properties, $22.9 million on our Canadian crude oil properties and $33.1 million on our Marcellus natural gas assets. The decrease in capital spending in 2020 compared to prior years was mainly due to minimal drilling and completions activity in North Dakota during the second and third quarters of 2020 in response to low crude oil prices as a result of the COVID-19 pandemic. Through our capital program in 2020, we added 16.7 MMBOE of gross proved plus probable reserves, replacing 50% of our 2020 production, including economic factors and technical revisions and before accounting for acquisitions and divestments. Excluding economic factors, we replaced 89% of total 2020 production and added 29.2 MMBOE of gross proved plus probable reserves.

Property and land acquisitions in 2020 totaled $10.1 million, which included minor acquisitions of leases and undeveloped land. We recorded net divestments of $6.1 million in 2020.

Subsequent to the year end, on January 25, 2021, Enerplus entered into the Purchase Agreement to acquire the outstanding equity interests of Bruin for total cash consideration of US$465 million, subject to certain purchase price adjustments. Closing of the Bruin Acquisition is expected to occur in early March 2021.

2019

Capital spending in 2019 totaled $618.9 million, including $531.7 million on our U.S. crude oil properties, $34.8 million on our Canadian crude oil properties and $49.3 million on our Marcellus natural gas assets. Through our capital program in 2019, we added 51.0 MMBOE of gross proved plus probable reserves, replacing 139% of our 2019 production, before accounting for acquisitions and divestments. In 2019, we spent $5.1 million on line fill to meet the requirements of a multi-year transportation contract that began in March 2019.

Property and land acquisitions in 2019 totaled $24.4 million and consisted primarily of undeveloped land in North Dakota. We recorded net divestments of $9.6 million related to the sale of properties in southeastern Saskatchewan with associated production of approximately 350 bbls/day.

2018

Capital spending in 2018 totaled $593.9 million, 30% higher than 2017. In 2018, we spent $474.4 million on our U.S. crude oil properties, $46.3 million on our Canadian crude oil properties, and $66.2 million on our Marcellus natural gas assets. In 2018, we added 65.7 MMBOE of gross proved plus probable reserves, replacing 194% of our 2018 production, before accounting for acquisitions and divestments.

Property and land acquisitions in 2018 totaled $25.8 million and included land acquisitions in Colorado and a property swap in North Dakota. We recorded net divestments of $6.9 million in 2018, primarily related to a property swap in North Dakota.

2021 Guidance

Our capital spending guidance range for 2021 is $335 million to $385 million, and assumes closing of the Bruin Acquisition in early March 2021.

Depletion, Depreciation and Accretion (“DD&A”)


($ millions, except per BOE amounts)	2020		2019		2018
DD&A expense	$	293.2	$	356.8	$	304.3
Per BOE	$	8.83	$	9.68	$	8.94

DD&A of PP&E is recognized using the unit of production method based on proved reserves. We recorded DD&A of $293.2 million during 2020, a decrease compared to $356.8 million in 2019, as a result of lower overall production volumes and the impact of PP&E impairments and decreased capital activity in 2020.

Impairments

PP&E

Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country cost centre basis using estimated after-tax future net cash flows discounted at 10 percent from proved reserves (“Standardized Measure”), using constant prices as defined by the SEC. SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity prices. The Standardized Measure is not related to Enerplus’ investment criteria and is not a fair value-based measurement, but rather a prescribed accounting calculation. Impairments are non-cash and are not reversed in future periods under U.S. GAAP.

18 ENERPLUS 2020 FINANCIAL SUMMARY

Trailing twelve month average crude oil and natural gas prices declined throughout 2020. For the twelve months ended December 31, 2020, we recorded a non-cash PP&E impairment of $994.8 million (Canadian cost centre: $134.4 million, U.S. cost centre: $860.4 million). There were no impairments recorded in 2019 and 2018.

Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. For the upcoming year, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense. See "Risk Factors and Risk Management - Risk of Impairment of Oil and Gas Properties, Deferred Tax Assets and Goodwill" in this MD&A.

The following table outlines the twelve-month average trailing benchmark prices and exchange rates used in our ceiling test at December 31, 2020, 2019 and 2018:


	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub		Exchange Rate
Year	US$/bbl		CDN$/bbl		Gas US$/Mcf		US/CDN
2020	$	39.54	$	45.56	$	2.00	1.34
2019	$	55.85	$	66.73	$	2.58	1.33
2018	$	65.56	$	69.58	$	3.10	1.28

Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. Goodwill is stated at cost less impairment and is not amortized or deductible for income tax purposes.

During 2020, we recorded a non-cash goodwill impairment of $202.8 million related to our U.S. reporting unit. The impairment was a result of the deterioration in macroeconomic conditions and low commodity prices due to the COVID-19 pandemic, which resulted in a reduction in fair value of the U.S. reporting unit and a full write down of our U.S. goodwill asset. In 2019, we recorded a non-cash goodwill impairment of $451.1 million representing the full value of the goodwill attributable to our Canadian reporting unit. At December 31, 2020, there was no goodwill remaining on our Condensed Consolidated Balance Sheet.

Asset Retirement Obligation

In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets, such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on our balance sheet are based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate and the timing of the costs to be incurred in future periods.

We have estimated the net present value of our asset retirement obligation to be $130.2 million at December 31, 2020, compared to $138.0 million at December 31, 2019. See Note 8 to the Financial Statements for further information.

We take an active approach to managing our abandonment, reclamation and remediation obligations. During 2020, we spent $17.7 million (2019 – $16.7 million) on our asset retirement obligations and we expect to spend approximately $16.5 million in 2021. The majority of our abandonment, reclamation and remediation costs are expected to be incurred between 2024 and 2046. We do not reserve cash or assets for the purpose of funding our future asset retirement obligations. Any abandonment, reclamation and remediation costs are anticipated to be funded out of adjusted funds flow and our bank credit facility.

Leases

Enerplus recognizes Right-Of-Use (“ROU”) assets and lease liabilities on the Consolidated Balance Sheet for qualifying leases with a term greater than 12 months. We incur lease payments related to office space, drilling rig commitments, vehicles and other equipment. Total lease liabilities included on our balance sheet are based on the present value of lease payments over the lease term. Total ROU assets included on our balance sheet represent our right to use an underlying asset for the lease term. At December 31, 2020, our total lease liability was $36.8 million compared to $53.1 million at December 31, 2019. The decrease was largely due to terminated contracts during 2020. At December 31, 2020, our ROU asset was $32.9 million, which equates to our lease liabilities less lease incentives. See Note 9 to the Consolidated Financial Statements for further details.

ENERPLUS 2020 FINANCIAL SUMMARY 19

Income Taxes


($ millions)	2020		2019		2018
Current tax expense/(recovery)	$	(14.6)	$	(33.4)	$	(27.1)
Deferred tax expense/(recovery)		(246.2)		81.3		130.3
Total tax expense/(recovery)	$	(260.8)	$	47.9	$	103.2

In 2020, we recorded a current tax recovery of $14.6 million compared to $33.4 million in 2019 and $27.1 million in 2018. The recovery in 2020 related primarily to the recognition of our final U.S. Alternative Minimum Tax ("AMT") refund. The recovery in 2019 was related to the favorable settlement of a tax dispute in Canada of $13.9 million and the reclassification of the AMT refund of $13.9 million. The recovery in 2018 was primarily related to the AMT refund reclassification of $27.2 million.

In 2020, we recorded a deferred income tax recovery of $246.2 million compared to expenses of $81.3 million in 2019 and $130.3 million in 2018. The recovery in 2020 is primarily due to lower income in 2020 from non-cash PP&E impairments in both our Canadian and U.S. cost centres. The deferred tax expense in 2019 included a $22.7 million expense from the remeasurement of our net Canadian deferred income tax assets for the change in the Alberta corporate income tax rate from 12% to 8%.

Each period, we assess the recoverability of our deferred tax assets to determine whether it is more likely than not all or a portion of our deferred tax assets will not be realized. In making that assessment, we consider the available positive and negative evidence including future taxable income and reversing existing temporary differences. We have evaluated the overall net deferred income tax asset and concluded that it is more likely than not that our non-capital Canadian deferred income tax assets will be realized as there is sufficient future taxable income to realize the benefit. As a result, for 2020 we have recovered the valuation allowance previously recorded against the Canadian deferred income tax assets. Our remaining valuation allowance is primarily related to our capital loss carryforward balance. We do not anticipate future capital gains that will allow us to utilize these losses. No valuation allowance was recorded against our U.S. deferred income tax assets. This assessment is primarily the result of projecting future taxable income using total proved and probable reserves at forecast average prices and costs. There is risk of further valuation allowance in future periods if commodity prices weaken or other evidence indicates more of our deferred income tax assets will not be realized. After recording the valuation allowance recovery, our overall net deferred income tax asset was $607.0 million as at December 31, 2020 (December 31, 2019 - $372.5 million).

Our estimated tax pools at December 31, 2020 are as follows:


Pool Type ($ millions)	2020
Canada
Canadian oil and gas property expense	$	8
Canadian development expense		117
Canadian exploration expense		238
Undepreciated capital costs		170
Non-capital losses and other credits		294
		827
U.S.
Net operating losses and other credits	$	1,203
Depletable and depreciable assets		775
		1,978
Total tax pools and credits	$	2,805

Capital losses	$	1,053

LIQUIDITY AND CAPITAL RESOURCES

There are numerous factors that influence how we assess our liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging, share repurchases and dividend levels. We also assess our leverage relative to our most restrictive debt covenant, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At December 31, 2020, our senior debt to adjusted EBITDA ratio was 1.4x and our net debt to adjusted funds flow ratio increased to 1.0x. Although it is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate our liquidity. Refer to the definitions and footnotes below.

Total debt net of cash at December 31, 2020 decreased to $376.0 million, compared to $455.0 million at December 31, 2019. Total debt was comprised of $490.4 million in senior notes less $114.5 million in cash. During the year we made scheduled repayments of US$81.6 million on our 2009 and 2012 senior notes using cash on hand. Our next scheduled senior note repayments of US$59.6 million and US$22.0 million are due in May and June 2021, respectively, with remaining maturities extending to 2026. At December 31, 2020, we were undrawn on our US$600 million bank credit facility.

20 ENERPLUS 2020 FINANCIAL SUMMARY

Our adjusted payout ratio, which is calculated as cash dividends plus capital, office expenditures and line fill divided by adjusted funds flow, was 90% for 2020 compared to 93% in 2019.

Our working capital deficiency, excluding cash and cash equivalents and current derivative financial assets and liabilities, increased to $257.8 million at December 31, 2020 from $210.4 million at December 31, 2019 due to a reduction in accrued revenues as a result of lower production and realized commodity prices and the receipt of the remaining AMT refunds. Our working capital varies primarily due to the timing of the cash realization of our current assets and current liabilities, and the current level of business activity, including our capital spending program, along with commodity price volatility. We expect to finance our working capital deficit and ongoing working capital requirements through cash, adjusted funds flow and our bank credit facility. In addition, we have sufficient liquidity to meet our financial commitments for the near term, as disclosed under “Commitments”.

During 2020, a total of $29.2 million was returned to shareholders through the repurchase of 340,434 common shares under our Normal Course Issuer Bid (“NCIB”) at an average price of $7.44 per share and dividend payments of $26.7 million. In comparison, we returned a total of $206.5 million to shareholders in 2019 through the repurchase of 18,231,401 common shares under the NCIB at an average price of $9.80 per share and dividend payments of $27.7 million. We expect to continue to pay monthly dividends to our shareholders of $0.01 per share in 2021; however, if economic conditions change, we may make adjustments.

On January 25, 2021, Enerplus entered into the Purchase Agreement to acquire all the outstanding equity interests of Bruin for total cash consideration of US$465 million, subject to certain purchase price adjustments. Enerplus will not assume any debt of Bruin as a part of the Bruin Acquisition, which is expected to close in early March 2021.

We intend to fund a portion of the purchase price of the Bruin Acquisition with a new three-year, senior unsecured US$400 million Term Facility. The Term Facility will include financial and other covenants and pricing consistent with Enerplus' existing US$600 million revolving credit facility, which matures October 31, 2023. Funding under the Term Facility is subject to limited conditions, including completion of the Bruin Acquisition and delivery of customary credit facility documentation. Following the announcement of the Bruin Acquisition, Enerplus completed a bought deal equity financing, issuing 33.1 million common shares at a price of $4.00 per share for gross proceeds of $132.3 million ($126.2 million, net of issuance costs). The net proceeds will be used to fund the remainder of the purchase price. We expect to be undrawn on our US$600 million credit facility upon close of the Bruin Acquisition.

At December 31, 2020, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Our bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.

The following table lists our financial covenants at December 31, 2020:


Covenant Description		December 31, 2020
Bank Credit Facility:	Maximum Ratio
Senior debt to adjusted EBITDA⁽¹⁾	3.5x	1.4x
Total debt to adjusted EBITDA⁽¹⁾	4.0x	1.4x
Total debt to capitalization	55%	24%

Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA⁽¹⁾⁽²⁾	3.0x – 3.5x	1.4x
Senior debt to consolidated present value of total proved reserves⁽³⁾	60%	29%

	Minimum Ratio
Adjusted EBITDA to interest ⁽¹⁾	4.0x	13.2x

Definitions

“Senior Debt” is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended December 31, 2020 were $96.4 million and $373.1 million, respectively.

“Total Debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.

“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $1.1 billion adjustment related to our adoption of U.S. GAAP.

Footnotes

(1)	See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income.

(2)	Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

(3)	Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.

ENERPLUS 2020 FINANCIAL SUMMARY 21

Counterparty Credit

CRUDE OIL AND NATURAL GAS SALES COUNTERPARTIES

Our crude oil and natural gas receivables are with customers in the crude oil and gas industry and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. A credit review process is in place to assess and monitor our counterparties’ creditworthiness on a regular basis. This process involves reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted, we obtain financial assurances such as letters of credit, parental guarantees or third-party insurance to mitigate a portion of our credit risk. This process is utilized for both our crude oil and natural gas sales counterparties as well as our financial derivative counterparties.

FINANCIAL DERIVATIVE COUNTERPARTIES

We are exposed to credit risk in the event of non-performance by our financial counterparties regarding our derivative contracts. We mitigate this risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have International Swaps and Derivatives Association (“ISDA”) agreements in place with the majority of our financial counterparties. These agreements provide some credit protection by generally allowing parties to aggregate amounts owing to each other under all outstanding transactions and settle with a single net amount in the case of a credit event. To date we have not experienced any losses due to non-performance by our derivative counterparties. All of our derivative counterparties are considered investment grade. At December 31, 2020, we had $3.6 million in financial derivative assets offset by $19.3 million of financial derivative liabilities resulting in a net liability position of $15.7 million.

Dividends


($ millions, except per share amounts)	2020		2019		2018
Cash dividends⁽¹⁾	$	26.7	$	27.7	$	29.3
Per weighted average share (Basic)	$	0.12	$	0.12	$	0.12

(1)	Excludes changes in non-cash financing working capital. See Note 18(b) of the Consolidated Financial Statements for additional information.

We reported total dividends of $26.7 million or $0.12 per share to our shareholders in 2020. During 2019 and 2018, we reported total dividends of $27.7 million or $0.12 per share and $29.3 million or $0.12 per share, respectively.

The dividend is part of our strategy to return capital to our shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders’ Capital


	2020		2019		2018
Share capital ($ millions)	$	3,097.0	$	3,088.1	$	3,337.6

Common shares outstanding (thousands)		222,548		221,744		239,411
Weighted average shares outstanding – basic (thousands)		222,503		231,334		244,076
Weighted average shares outstanding – diluted (thousands)		222,503		231,334		247,261

For the twelve months ended December 31, 2020, a total of 2,044,718 units vested pursuant to our treasury settled LTI plans (2019 – 1,007,234; 2018 – 2,539,498). In total, 1,160,000 common shares were issued from treasury and $13.8 million was transferred from paid-in capital to share capital (2019 – 564,000 and $4.4 million; 2018 – 2,539,498 and $23.4 million). We elected to cash settle the remaining units related to the required tax withholdings (2020 – $7.2 million, 2019 – $5.0 million; 2018 - nil). During 2020, no common shares were issued pursuant to our stock option plan (2019 – nil; 2018 – 668,000 common shares for $9.1 million).

During the twelve months ended December 31, 2020, we repurchased 340,434 common shares under the previous NCIB at an average price of $7.44 per share, for total consideration of $2.5 million (2019 – 18,231,401, $178.8 million; 2018 – 5,925,084, $79.0 million). Of the amount paid, $4.7 million was charged to share capital and $2.2 million was credited to accumulated deficit (2019 – $253.9 million; $75.1 million; 2018 – $82.6 million and $3.6 million). We chose not to renew our NCIB after its expiry on March 25, 2020 in order to preserve capital and maintain our balance sheet strength.

Subsequent to December 31, 2020, on February 3, 2021, Enerplus issued 33,062,500 common shares at a price of $4.00 per common share for gross proceeds of $132.3 million ($126.2 million net of issue costs) pursuant to a bought deal prospectus offering under its base shelf prospectus.

As of February 18, 2021, we had 256,235,100 common shares outstanding. In addition, an aggregate of 5,475,625 common shares may be issued to settle outstanding grants under our share award incentive plan (in the form of PSUs and RSUs), assuming the maximum payout multiplier of 2.0 times for the PSUs. For further details see Note 14 to the Financial Statements.

22 ENERPLUS 2020 FINANCIAL SUMMARY

Commitments

We have the following minimum annual contractual commitments:


													Total
			Minimum Annual Commitment Each Year										Committed
($ millions)	Total		2021		2022		2023		2024		2025		after 2025
Senior notes⁽¹⁾	$	490.4	$	103.8	$	128.0	$	102.6	$	102.6	$	26.7	$	26.7
Transportation commitments⁽²⁾		290.0		44.5		30.4		29.4		29.1		29.1		127.5
Processing commitments		9.5		1.6		1.5		1.5		1.5		1.5		1.9
Operating lease obligations		40.0		14.6		8.3		7.0		6.2		1.2		2.7
Total commitments⁽³⁾	$	829.9	$	164.5	$	168.2	$	140.5	$	139.4	$	58.5	$	158.8

(1)	Interest payments have not been included.

(2)	Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(3)	US$ commitments have been converted to CDN$ using the December 31, 2020 foreign exchange rate of 1.27.

In the Marcellus, we have firm transportation agreements in place for approximately 68,000 Mcf/day of natural gas, which expire between 2022 and 2036. This includes an agreement for firm pipeline capacity on the Tennessee Gas Pipeline from our Marcellus producing region to downstream connections for 30,000 Mcf/day of natural gas until mid-2027, reducing to 15,000 Mcf/day for an additional 9 years, with a total estimated transportation commitment of US$76.6 million through 2036. In the Bakken region, we hold firm pipeline capacity to transport a portion of our crude oil production to the U.S. Gulf Coast, which expires in early 2029.

In Canada, we have various firm transportation agreements for approximately 1,800 BOE/day of our crude oil and natural gas liquids production in 2021, decreasing to approximately 820 BOE/day on average from 2022 to 2027. We have firm natural gas liquids fractionation contracts for 1,125 bbls/day through 2027, and firm natural gas transportation contracts for approximately 30,000 Mcf/day as of December 31, 2020.

Our commitments and contingencies are more fully described in Note 16 to the Financial Statements. Our operating lease obligations are detailed in Note 9 to the Financial Statements.

ENERPLUS 2020 FINANCIAL SUMMARY 23

SELECTED ANNUAL CANADIAN AND U.S. FINANCIAL RESULTS


	Year ended							Year ended
	December 31, 2020							December 31, 2019
($ millions, except per unit amounts)		Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes⁽¹⁾
Crude oil (bbls/day)			7,178		38,243		45,421		8,625		41,079		49,704
Natural gas liquids (bbls/day)			628		5,005		5,633		895		4,034		4,929
Natural gas (Mcf/day)			12,481		225,376		237,857		23,706		254,745		278,451
Total average daily production (BOE/day)			9,886		80,811		90,697		13,471		87,571		101,042

Pricing⁽²⁾
Crude oil (per bbl)		$	36.14	$	45.89	$	44.35	$	59.71	$	70.92	$	68.98
Natural gas liquids (per bbl)			21.32		8.90		10.29		28.82		12.16		15.19
Natural gas (per Mcf)			2.59		1.83		1.87		2.42		2.91		2.87

Capital Expenditures
Capital spending		$	23.4	$	268.0	$	291.4	$	37.9	$	581.0	$	618.9
Acquisitions			2.6		7.5		10.1		6.0		18.4		24.4
Divestments			0.1		(6.2)		(6.1)		(9.0)		(0.6)		(9.6)

Netback⁽³⁾ Before Hedging
Crude oil and natural gas sales		$	113.6	$	809.9	$	923.5	$	220.8	$	1,352.1	$	1,572.9
Royalties			(17.1)		(169.2)		(186.3)		(43.5)		(274.6)		(318.1)
Production taxes			(1.1)		(48.8)		(49.9)		(2.6)		(80.5)		(83.1)
Operating expenses			(55.9)		(207.7)		(263.6)		(72.1)		(218.7)		(290.8)
Transportation costs			(8.7)		(123.7)		(132.4)		(10.1)		(134.8)		(144.9)
Netback before hedging		$	30.8	$	260.5	$	291.3	$	92.5	$	643.5	$	736.0

Other Expenses
Asset impairment		$	134.4	$	860.4	$	994.8	$	—	$	—	$	—
Goodwill impairment			202.8		—		202.8		451.1		—		451.1
Commodity derivative instruments loss/(gain)			(108.8)		—		(108.8)		66.1		—		66.1
General and administrative expense⁽⁴⁾			2.3		55.3		57.6		29.0		43.8		72.8
Current income tax expense/(recovery)			—		(14.5)		(14.5)		(13.9)		(19.5)		(33.4)

(1)	Company interest volumes.

(2)	Before transportation costs, royalties and the effects of commodity derivative instruments.

(3)	See “Non-GAAP Measures” section in this MD&A.

(4)	Includes share-based compensation.

THREE YEAR SUMMARY OF KEY MEASURES


($ millions, except per share amounts)	2020		2019		2018
Crude oil and natural gas sales, net of royalties	$	737.2	$	1,254.8	$	1,292.7

Net income/(loss)		(923.4)		(259.7)		378.3
Per share (Basic)		(4.15)		(1.12)		1.55
Per share (Diluted)		(4.15)		(1.12)		1.53

Adjusted net income⁽¹⁾		19.8		243.2		344.8

Cash flow from operating activities		446.4		694.2		738.8
Adjusted funds flow⁽¹⁾		358.2		709.0		753.5

Cash dividends⁽²⁾		26.7		27.7		29.3
Per share (Basic)⁽²⁾		0.12		0.12		0.12
Total assets		1,466.5		2,565.8		3,118.3
Total debt		490.4		606.5		696.8

Total debt net of cash⁽¹⁾		376.0		455.0		333.5

(1)	See “Non-GAAP Measures” section of this MD&A.

(2)	Calculated based on dividends paid or payable.

24 ENERPLUS 2020 FINANCIAL SUMMARY

2020 versus 2019

Oil and natural gas sales, net of royalties, were $737.2 million in 2020 compared to $1,254.8 million in 2019 due to lower realized commodity prices and decreased production in 2020.

We reported a net loss of $923.4 million in 2020 compared to a net loss of $259.7 million in 2019. The decrease in 2020 was primarily due to a $994.8 million non-cash PP&E impairment and a $202.8 million non-cash U.S. goodwill impairment.

Cash flow from operating activities and adjusted funds flow decreased to $446.4 million and $358.2 million, respectively, in 2020 from $694.2 million and $709.0 million in 2019. The decrease was primarily the result of a $517.6 million decrease in net crude oil and natural gas sales due to lower realized commodity prices and lower production, partially offset by a $115.6 million increase in realized commodity derivative gains.

2019 versus 2018

Oil and natural gas sales, net of royalties, were $1,254.8 million in 2019 compared to $1,292.7 million in 2018, with the impact of higher production more than offset by lower commodity prices.

We reported a net loss of $259.7 million in 2019 compared to net income of $378.3 million in 2018. The decrease in 2019 was primarily due to a $451.1 million non-cash Canadian goodwill impairment, along with losses on commodity derivative instruments.

Cash flow from operations and adjusted funds flow decreased to $694.2 million and $709.0 million, respectively, from $738.8 million and $753.5 million, respectively, in 2018. Crude oil and natural gas sales decreased due to lower realized commodity prices, while operating expenses increased over the same period, in part due to higher liquids volumes. These decreases were offset by realized commodity derivative gains in 2019 compared to losses in 2018.

QUARTERLY FINANCIAL INFORMATION


	Crude oil and
	Natural Gas Sales,		Net		Net Income/(Loss) Per Share
($ millions, except per share amounts)	Net of Royalties		Income/(Loss)		Basic		Diluted
2020
Fourth Quarter	$	195.1	$	(204.2)	$	(0.92)	$	(0.92)
Third Quarter		191.9		(112.8)		(0.51)		(0.51)
Second Quarter		122.1		(609.3)		(2.74)		(2.74)
First Quarter		228.1		2.9		0.01		0.01
Total 2020	$	737.2	$	(923.4)	$	(4.15)	$	(4.15)
2019
Fourth Quarter	$	327.0	$	(429.1)	$	(1.93)	$	(1.93)
Third Quarter		318.9		65.1		0.28		0.28
Second Quarter		321.4		85.1		0.36		0.36
First Quarter		287.5		19.2		0.08		0.08
Total 2019	$	1,254.8	$	(259.7)	$	(1.12)	$	(1.12)

Crude oil and natural gas sales, net of royalties, decreased in 2020 compared to 2019 due to lower realized commodity prices, and decreased production. We reported a net loss in 2020 due to a non-cash goodwill impairment of $202.8 million on our U.S. reporting unit and a non-cash PP&E impairment of $994.8 million recorded in the twelve months ended December 31, 2020.

During 2019, we reported crude oil and gas sales, net of royalties, of $1,254.8 million. We reported a net loss in 2019 due to a non-cash impairment of $451.1 million on our Canadian goodwill asset recorded in the fourth quarter.

ENERPLUS 2020 FINANCIAL SUMMARY 25

ENVIRONMENT, SOCIAL AND GOVERNANCE (“ESG”)

Enerplus believes that minimizing the environmental impacts of its operations is a foundational tenet of corporate responsibility. Moreover, as the global economy transitions to a lower carbon future, climate related policies and regulations around carbon emissions are becoming increasingly stringent, requiring businesses to adapt to support long-term business resilience. We intend to continue to improve energy efficiencies and proactively manage our environmental impact in compliance with applicable government regulations, including regulations enacted at the provincial, state and federal jurisdictions in which we operate.

Our Board of Directors is responsible for overseeing our ESG initiatives. Specific accountability for our six material focus areas have been mapped to the relevant Board subcommittees, including the Compensation and Human Resources Committee, the Safety and Social Responsibility Committee (the “S&SR Committee”) and the Corporate Governance and Nominating Committee. The six material focus areas are:

●

Greenhouse Gas (“GHG”) Emissions

●

Water Management

●

Culture

●

Community Engagement

●

Health and Safety

●

Board Constitution and Culture

As part of our continued integration of ESG issues into our business strategy and operations, early in 2020 we established targets for reducing GHG emissions intensity and freshwater use. Using 2019 as a baseline, we targeted a 10% reduction of our scope 1 and 2 GHG emissions per BOE in 2020. Based on preliminary estimates, we expect to have reduced our 2020 GHG emissions intensity by more than 20% compared to 2019. Finalized emissions will be available in our annual ESG Report and Data Tables, expected to be published later in 2021.

In 2020, we targeted a reduction in freshwater use per well completion in North Dakota by 15%, compared to 2019. We ended 2020 using, on average, 23% less freshwater per well completion in North Dakota, compared to 2019.

We set a Health & Safety target of reducing our Lost Time Injury Frequency (LTIF) by 25%, on average, from 2020 to 2023, relative to a 2019 baseline. In 2020, we reported an LTIF of 0.08 injuries per 200,000 worker hours, a 67% improvement from 2019. We will continue to update the market as we progress closer to the end of our 2023 target. We are pleased to announce our 2020 LTIF was the best safety performance in our organization’s history.

We expect to integrate the assets acquired through the Bruin Acquisition into our existing ESG strategy throughout 2021. More information will be available with the publication of our 2021 ESG Report later in the year.

We have a Health & Safety Policy (“H&S Policy”) and an Environmental, Social and Governance Policy (“ESG Policy”), which articulate our commitment to health and safety, community engagement, environmental and regulatory compliance, and social and governance practices. Our Board of Directors and President & Chief Executive Officer are ultimately accountable for ensuring compliance with these policies. The S&SR Committee of our Board of Directors is responsible for overseeing our H&S performance. The Board of Directors are responsible for overseeing our ESG performance and strategy. This ensures there are adequate systems in place to support ongoing compliance, and to plan the Company’s activities in a safe, socially responsible and sustainable manner.

The S&SR Committee regularly reviews health, safety, environmental and regulatory updates, and risks. At present, we believe we are, and expect to continue to be, in compliance with all material applicable environmental laws and regulations and we have included appropriate amounts in our capital expenditure budget to continue to meet our ongoing environmental obligations. However, increased capital and operating costs may be incurred if regulations in Canada or the U.S. impose more stringent compliance requirements.

Annually, we publish an ESG Report in accordance with the Sustainability Accounting Standards Boards (SASB) materiality metrics, the Global Reporting Initiative (GRI) Core option, and the International Petroleum Industry Environmental Conservation Association’s (“IPIECA”) “Oil and gas industry guidance on voluntary sustainability reporting” (a joint publication with the American Petroleum Institute and the International Association of Oil & Gas Producers). The report summarizes our environmental, safety, social responsibility and governance performance, and can be found on our website at www.enerplus.com.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. GAAP requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital spending. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

26 ENERPLUS 2020 FINANCIAL SUMMARY

Crude Oil and Natural Gas Properties and Reserves

Enerplus follows the full cost method of accounting for crude oil and natural gas properties. The process of estimating reserves is critical in determining several accounting estimates including the Company’s depletion, ceiling test, valuation allowance on deferred income tax assets, gain or loss calculations and purchase equations. The estimation of crude oil and natural gas reserves and the related present value of future cash flows involves the use of independent reservoir engineering specialists and numerous estimates and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Estimating reserves requires significant judgments based on available geological, geophysical, engineering and economic data. These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and natural gas prices, operating costs and royalty burdens change. Reserves estimates impact net income through depletion, the determination of asset retirement obligation and the application of impairment tests. Revisions or changes in reserves estimates can have either a positive or a negative impact on net income.

Asset Impairment

Ceiling Test

Under the full cost method of accounting for PP&E, we are subject to quarterly calculations of a ceiling or limitation on the amount of our crude oil and natural gas properties that can be capitalized on our balance sheet by cost centre. If the net capitalized costs of our crude oil and natural gas properties exceed the cost centre ceiling, we are subject to a ceiling test write-down to the extent of such excess. These write-downs reduce net income and impact shareholders’ equity in the period of occurrence and result in lower depletion expense in future periods. The volume and discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of crude oil and natural gas that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average crude oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that further write-downs of our crude oil and natural gas properties could occur in the future. Under U.S. GAAP impairments are not reversed in future periods.

Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net assets acquired. Goodwill is allocated to reporting units and is assessed for impairment at least annually. To assess impairment, the Company first evaluates qualitative factors, such as industry and market considerations and overall financial performance, to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value including goodwill, a quantitative impairment test is performed. If the carrying amount of the reporting unit exceeds its related fair value, goodwill is written down to the reporting unit’s fair value. The fair value used in the impairment test is based on estimates of discounted future cash flows which involve assumptions of natural gas and liquids reserves, including commodity prices, future costs and discount rates. At December 31, 2020, there was no goodwill remaining on our Condensed Consolidated Balance Sheet.

Income Taxes

Management makes certain estimates in calculating deferred tax assets and liabilities, as well as income tax expense. These estimates often involve judgment regarding differences in the timing and recognition of revenue and expense for tax and financial reporting purposes as well as the tax basis of our assets and liabilities at the balance sheet date before tax returns are completed. Additionally, we must assess the likelihood we will be able to recover or utilize our deferred tax assets. We must record a valuation allowance against a deferred tax asset where all or a portion of that asset is not expected to be realized. In evaluating whether a valuation allowance should be applied, we consider evidence such as future taxable income, among other factors, both positive and negative. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely than not that the asset will be realized.

Asset Retirement Obligation

Management calculates the asset retirement obligation based on estimated costs to abandon, reclaim and remediate its ownership interest in all wells, facilities and pipelines and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and depleted over its useful life. There are uncertainties related to asset retirement obligations and the impact on the financial statements could be material as the eventual timing and costs for the obligations could differ from our estimates. Factors that could cause our estimates to differ include any changes to laws or regulations, reserves estimates, costs and technology.

ENERPLUS 2020 FINANCIAL SUMMARY 27

Business Combinations

Management makes various assumptions in determining the fair value of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we, and independent evaluators, estimate crude oil and natural gas reserves and future prices of crude oil and natural gas.

Derivative Financial Instruments

We utilize derivative financial instruments to manage our exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates and counterparty credit risk.

RECENT U.S. GAAP ACCOUNTING AND RELATED PRONOUNCEMENTS

Refer to Note 2(p) in our Financial Statements for Standards and Interpretations that were issued but not yet effective at December 31, 2020.

RISK FACTORS AND RISK MANAGEMENT

Risks Relating to the Impact of the COVID-19 Pandemic and Continued Weakness and Volatility in Commodity Prices

The global outbreak of the COVID-19 pandemic and the ongoing uncertainty as to the extent and duration of this pandemic, as well as governmental authorities response thereto, has resulted in, and continues to result in, among other things: increased volatility in financial markets, including credit markets and foreign currency and interest exchange rates; disruptions to global supply chains; labour shortages; reductions in trade volumes; temporary operational restrictions, quarantine orders, business closures and travel bans; an overall slowdown in the global economy; political and economic instability; and civil unrest. In particular, the COVID-19 pandemic has resulted in, and continues to result in, a reduction in the demand for crude oil and natural gas.

In addition, recent market events and conditions, including excess global crude oil and natural gas supply and decreased global demand due to the COVID-19 pandemic, have caused significant weakness and volatility in commodity prices. While the commodity prices began to stabilize as global economies began to re-open, the recent resurgence of COVID-19 cases in certain geographic areas, and the possibility that a resurgence may occur in other areas, has resulted in the re-imposition of certain restrictions noted above by local authorities. This further increases the risk and uncertainty as to the extent and duration of the COVID-19 pandemic and the resultant impact on commodity demand and prices. The overall result of these recent events and conditions could lead to a prolonged period of depressed prices for crude oil and natural gas which may result in further curtailments, voluntary or otherwise. We are continuing to evaluate the impact of the COVID-19 pandemic and the continued commodity environment instability on our business, financial condition and results of operations; however, the full extent of such impact continues to be unknown at this time and will depend on future developments (which are highly uncertain and cannot be predicted with any degree of confidence) and may be adverse and could result, among other things, in PP&E or deferred tax asset impairment, or exceeding our debt covenants, among others. See disclosure under "Impairment – PP&E", “Income Taxes” and "Liquidity and Capital Resources" in this MD&A.

We are also subject to risks relating to the health and safety of our personnel, including the potential for a slowdown or temporary suspension of our operations in locations impacted by an outbreak or further regulatory changes. Such a suspension in operations could also be mandated by governmental authorities in response to the COVID-19 pandemic. This would negatively impact our production volumes, which could adversely impact our business, financial condition and results of operations.

Depending on the extent and duration of the COVID-19 pandemic, it may also have the effect of heightening many of the other risks described in the Annual Information Form and the Annual MD&A.

28 ENERPLUS 2020 FINANCIAL SUMMARY

Commodity Price Risk

Our operating results and financial condition are dependent on the prices we receive for our crude oil, natural gas liquids, and natural gas production. These prices have fluctuated widely in response to a variety of factors including global and domestic supply and demand of crude oil, natural gas and natural gas liquids, actions taken by OPEC or non-OPEC members to set, maintain or alter production levels to help in achieving a balanced market, geopolitical uncertainty, sustained pandemics, including the COVID-19 pandemic, or epidemics that disrupt economies, whether local or global, impacting supply, demand and prices for crude oil, natural gas liquids and natural gas, economic conditions including currency fluctuations, global gross domestic product growth, weather conditions, the level of consumer demand, the ability to export oil and liquefied natural gas and natural gas liquids from North America and the supply and price of imported oil and liquefied natural gas, the production and storage levels of North American crude oil, natural gas and natural gas liquids, political stability, transportation facilities, availability of processing, fractionation and refining facilities, the effect of world-wide energy conservation and greenhouse gas reduction measures, the price and availability of alternative fuels and existing and proposed changes to government regulations and policy decisions, including moratoriums with respect thereto.

A future decline in crude oil or natural gas prices may have a material adverse effect on our operations and cash flows, financial condition, borrowing ability, levels of reserves and resources and the level of expenditures for the development of our crude 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 our production volumes, or our desire to market our production in unsatisfactory market conditions. Furthermore, we may be subject to the decisions of third party operators or to legislative decisions by regional governments who, independently and using different economic parameters, may decide to curtail or shut-in jointly owned production or to mandate industry-wide production curtailments.

We may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of crude oil, natural gas liquids, and natural gas price volatility. However, we do not hedge all of our production and expect there will always be a portion that remains unhedged. Furthermore, we may use financial derivative instruments that offer only limited protection within selected price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase. At February 18, 2021, we have hedged approximately 21,500 bbls/day and 17,000 bbls/day, respectively, of our expected crude oil production for 2021 and 2022, 60,000 Mcf/day of natural gas production for March 2021 and 100,000 Mcf/day of natural gas production for April 1 to October 31, 2021, at price levels disclosed in the “Price Risk Management” section above. Refer to the “Price Risk Management” section for further details on our price risk management program.

Risks Relating to Climate Change

Enerplus is subject to climate change related risks which are generally grouped into two categories: physical risks and transition risks. Physical risks include the impact that a change in climate could have on our operations, including limited water availability, severe weather or fire. These events may increase the cost of water, energy, insurance or capital projects, impacting our profitability. The physical risks of climate change may also result in operational delays, depending on the nature of the event. Enerplus does not believe that its current or near-term operations expose it to any particular physical risks which differ from those facing a typical North American onshore oil and gas producer, and currently cannot predict or quantify the potential financial impact of any such risks.

Transition risk is broader and relates to the consequences of a global transition to reduced carbon, including the risk of regulatory and policy change and reputational concerns. The growing push for decarbonization increases the risk of potentially burdensome regulatory and/or policy changes that could increase Enerplus’ risk in obtaining access to service providers, including but not limited to debt holders, insurers, and the investment community. In addition, Enerplus could also have stranded assets, i.e. be unable to obtain value for, or from, its reserves. More specific concerns of the fossil fuels, industry relate to GHG emissions, as well as water and land use, could also result in more stringent legislation, including requirements to significantly reduce GHG emissions, water consumption or setback requirements for facilities and wells, all of which could be costly to implement. For example, on January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the U.S. federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Failure to comply with such regulations and laws could also result in significant penalties being imposed. In addition, a potential increase in capital expenditures, operating expenses, abandonment and reclamation obligations and distribution costs or the loss of operating licenses, any of which may not be recoverable in the marketplace, could result in operations or growth projects becoming less profitable, uneconomic, or result in the Enerplus’ inability to continue development of assets. Additionally, there is a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector; both the Bank of Canada and the Federal Reserve of the United States have joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

ENERPLUS 2020 FINANCIAL SUMMARY 29

There is also a reputational risk associated with climate change, which considers the public perception of Enerplus’ role in the transition to a low carbon economy. We seek to mitigate this risk through a strong ESG program with six material focus areas which are overseen by the Company’s Board of Directors and applicable Board subcommittees. Our strategy is to be a “best in basin” operator – in the eyes of our shareholders, employees, contractors, regulators, communities and the general public. Despite these efforts, activities undertaken directly by Enerplus or its employees, or by others in industry, could adversely affect Enerplus’ reputation. If the reputation of the Corporation, or the oil and gas industry in general, is diminished, it could result in: the loss of employees or revenue; delays in regulatory approvals; increased operating, capital, financing and regulatory costs; reduced shareholder confidence and negative stock price movement.

Regulatory Risk and Greenhouse Gas Emissions

Government royalties, environmental laws and regulatory requirements can have a significant financial and operational impact on us. As an oil and gas producer, we operate under federal, provincial, state, tribal and municipal legislation and regulation that govern such matters as royalties, land tenure, prices, production rates, various environmental protection controls, well and facility design and operation, income taxes and the exportation of crude oil, natural gas and other products. We may be required to apply for regulatory approvals in the ordinary course of business. To the extent that we fail to comply with applicable government regulations or regulatory approvals, we may be subject to compliance and enforcement actions that are either remedial or punitive to deter future noncompliance. Such actions include fines or fees, notices of noncompliance, warnings, orders, curtailment, administrative sanctions and prosecution.

Government regulations may be changed from time to time in response to economic, political or socioeconomic conditions, including the election of new state, provincial or federal leaders. Additionally, our entry into new jurisdictions or adoption of new technology may attract additional regulatory oversight which could result in higher costs or require changes to proposed operations. U.S. federal and state and Canadian federal and provincial continue to scrutinize emissions, as well as the usage and disposal of chemicals and water used in fracturing procedures in the oil and gas industry; certain states have called for bans on oil and gas drilling using hydraulic fracturing and the new U.S. administration has taken actions towards fulfilling its initiative of curtailing hydraulic fracturing of federal lands. Additionally, various levels of U.S. and Canadian governments are considering or have implemented legislation to reduce emissions of greenhouse gases, including volatile organic compounds (“VOC”) and methane gas emissions.

The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations could negatively impact the development of crude oil and natural gas properties and assets, reduce demand for crude oil and natural gas or impose increased costs on oil and gas companies including taxes, fees or other penalties.

Although we have no control over these regulatory risks, we continuously monitor changes in these areas by participating in industry organizations, conferences, exchanging information with third party experts and employing qualified individuals to assess the impact of such changes on our financial and operating results. Accordingly, while we continue to prepare to meet the potential requirements at each of the provincial, state and federal levels, the actual cost impact and its materiality to our business remains uncertain.

Anticipated Benefits of Acquisitions or Divestments

From time to time, we may acquire additional crude 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 our ability to realize the anticipated growth opportunities from combining and integrating the acquired assets and properties into our existing business. These activities will require the dedication of substantial management effort, time, 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 risk factors specified in this MD&A relating to the crude oil and natural gas business and our operations, reserves and resources apply equally to future properties or assets that we may acquire. We conduct due diligence in connection with acquisitions, but there is no assurance that we will identify all the potential risks and liabilities related to such properties.

When acquiring assets, we are subject to inherent risks associated with predicting the future performance of those assets. We may make certain estimates and assumptions respecting the characteristics of the assets we acquire, that may not be realized over time. As such, assets acquired may not possess the value we attribute to them, which could adversely impact our future cash flows. To the extent that we make acquisitions with higher growth potential, the higher risks often associated may result in increased chances that actual results may vary from our 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 our engineers, and these initial assessments may differ significantly from our subsequent assessments. There is also no assurance that the acquired assets will be viewed favourably by our investors and could result in a negative effect to the price of our common shares.

30 ENERPLUS 2020 FINANCIAL SUMMARY

Certain acquisitions, and in particular acquisitions of higher risk/higher growth assets and the development of those acquired assets, may require capital expenditures and we may not receive cash flow from operating activities from these acquisitions for several years, or in amounts less than anticipated. Accordingly, the timing and amount of capital expenditures may adversely affect our cash flow.

The closing of the Bruin Acquisition is subject to satisfaction of certain closing conditions. There is no certainty, nor can we provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied. If the Bruin Acquisition is not completed as contemplated, Enerplus could suffer adverse consequences, including the loss of investor confidence. If the Bruin Acquisition is completed, there is a risk that some or all of the expected benefits of the Bruin Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods we anticipate.

We may also seek to divest of properties and assets from time to time. These divestments may consist of non-core properties or assets, or may consist of assets or properties that are being monetized to fund alternative projects or development or debt repayments. There can be no assurance that we will be successful, that we will realize the amount of desired proceeds, or that such divestments will be viewed positively by the financial markets. Divestments may negatively affect our results of operations or the trading price of our common shares. In addition, although divestments typically transfer future obligations to the buyer, we may not be exempt from certain future obligations, including abandonment, reclamation, and/or remediation if applicable, which may have an adverse effect on our operations and financial condition.

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through issuance of equity and debt in past years. Continued access to capital is dependent on our ability to optimize our existing assets and to demonstrate the advantages of the acquisition or development program that we are financing at the time, as well as investors’ view of the oil and gas industry overall. We may not be able to access the capital markets in the future on terms favorable to us, or at all. Our continued access to capital markets is dependent on corporate performance and investor perception of future performance (both corporately and for the oil and gas sector in general).

We are required to assess our foreign private issuer (“FPI”) status under U.S. securities laws on an annual basis. If we lose our FPI status, we may have restricted access to capital markets for a period of time until the required approvals are in place from the SEC.

Access to Transportation and Processing Capacity

Market access for crude oil, natural gas liquids and natural gas production in the U.S. and Canada is dependent on our ability, and the ability of our buyers as applicable, to obtain transportation capacity on third party pipelines and rail as well as access to processing facilities. As production increases in the regions where we operate, it is possible production may exceed the existing capacity of the gathering, pipeline, processing or rail infrastructure. While third party pipelines, processors and independent rail operators generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of capacity. There are occasionally operational reasons for curtailing transportation and processing capacity. Accordingly, there can be periods where transportation and processing capacity is insufficient to accommodate all the production from a given region, causing added expense and/or volume curtailments for all shippers. Our assets are concentrated in specific regions where government or other third parties could limit or ban the shipping of commodities by truck, pipeline or rail. Special interest groups and/or social instability could also prevent access to leased land or continue their opposition to infrastructure development, at either the regulatory or judicial level, including the ongoing matters with respect to DAPL (which are before the District Court for the District of Columbia), resulting in operational delays, or even the cancellation of construction of the required infrastructure, or the shutdown of already operating infrastructure projects, further impeding our ability to operate, produce and market our products. Additionally, the transportation of crude oil by rail has been under closer scrutiny by government regulatory agencies in Canada and the U.S. over the past few years. As a result, transporting crude oil by rail may carry a higher cost versus traditional pipeline infrastructure or other means of transporting production.

We monitor this risk for both the short and longer term through dialogue and review with the third party pipelines and other market participants. Where available and commercially appropriate, given the production profile and commodity, we attempt to mitigate transportation and processing risk by contracting for firm pipeline or processing capacity or using other means of transportation, including trucking or selling to third parties that have access to pipeline or rail capacity.

Risk of Curtailed or Shut-in Production

Should we be required to curtail or shut-in production as a result of low commodity prices, environmental regulation, government regulation or third party operational practices, it could result in a reduction to cash flow and production levels and may result in additional operating and capital costs for the well to achieve prior production levels. In addition, curtailments or shut-ins may cause damage to the reservoir and may prevent us from achieving production and operating levels that were in place prior to the curtailment or shutting-in of the reservoir. Combined with the ongoing volatility in commodity prices, any shortage in pipeline infrastructure in producing regions where we operate may result in discounted prices and an ongoing risk of price-related production curtailments.

ENERPLUS 2020 FINANCIAL SUMMARY 31

The recent changes in control of the U.S. Congress and the election of President Biden may result in legislative and regulatory changes that could have an adverse effect on Enerplus. In particular, President Biden has indicated that his administration will seek to curtail oil and gas development on federal lands, possibly through temporary or permanent bans on new leasing, delays or bans on the issuance of drilling permits, and his administration may pursue other regulatory initiatives, executive actions and legislation in support of his regulatory agenda. Implementation by the U.S. government of new legislative or regulatory policies could impose additional costs, decrease U.S. demand for our products, or otherwise negatively impact Enerplus, which may have a material adverse effect on our business, financial condition and operations.

Risk of Increased Capital or Operating Costs

Higher capital or operating costs associated with our operations will directly impact our capital efficiencies and cash flow. Capital costs of completions, specifically the costs of proppant, pumper services, and operating costs such as electricity, chemicals, supplies, energy services and labour costs, are a few of the costs that are susceptible to material fluctuation. Although we have a portion of our current capital and operating costs protected with existing agreements, changing regulatory conditions, such as potential new or revised regulations in the U.S. requiring certain raw materials, such as steel, for use on certain projects to be sourced from the U.S., or that goods and/or services be procured from specific vendors or classes of vendors on certain projects, may result in higher than expected supply costs for the company.

Production Replacement Risk

Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new land, reserves and/or resources and developing existing reserves and resources. Acquisitions of oil and gas assets will depend on our assessment of value at the time of acquisition and ability to secure the acquisitions generally through a competitive bid process.

Acquisitions and our development capital program are subject to investment guidelines, due diligence and review. Major acquisitions and our annual capital development budget are approved by the Board of Directors and where appropriate, independent reserve engineer evaluations are obtained.

Oil and Gas Reserves and Resources Risk

The value of our company is based on, among other things, the underlying value of our oil and gas reserves and resources. Geological and operational risks along with product price forecasts can affect the quantity and quality of reserves and resources and the cost of ultimately recovering those reserves and resources. Lower crude oil, natural gas liquids, and natural gas prices along with lower development capital spending associated with certain projects may increase the risk of write-downs for our oil and gas property investments. Changes in reporting methodology as well as regulatory practices can result in reserves or resources write-downs.

Each year, independent reserves engineers evaluate the majority of our proved and probable reserves as well as evaluate or audit the resources attributable to a significant portion of our undeveloped land. All reserves information, including our U.S. reserves, has been prepared in accordance with NI 51-101 standards. For U.S. GAAP accounting purposes, our proved reserves are estimated to be technically the same as our proved reserves prepared under NI 51-101 and have been adjusted for the effects of SEC constant prices. Independent reserves evaluations have been conducted on approximately 98% of the total proved plus probable net present value (discounted at 10% and using NI 51-101 standards) of our reserves at December 31, 2020. McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated 86% of our Canadian reserves and reviewed the internal evaluation completed by Enerplus on the remaining portion. McDaniel also evaluated 100% of the reserves associated with our U.S. tight oil assets. Netherland, Sewell & Associates, Inc. (“NSAI”) evaluated 100% of our U.S. Marcellus shale gas assets.

The evaluation of best estimate development pending contingent resources associated with our North Dakota assets was conducted by Enerplus’ qualified reserves evaluators and audited by McDaniel. NSAI evaluated our Marcellus shale gas best estimate development pending contingent resources.

The Reserves Committee of the Board of Directors and the Board of Directors has reviewed and approved the reserves and resources reports of the independent evaluators.

Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets

Under U.S. GAAP, the net capitalized cost of crude oil and natural 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 reporting date. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

32 ENERPLUS 2020 FINANCIAL SUMMARY

Under U.S. GAAP, the net deferred tax asset is limited to the estimate of future taxable income resulting from existing properties. We estimate future taxable income based on before-tax future net revenue from proved plus probable reserves, undiscounted, using forecast prices, and adjusted for other significant items affecting taxable income. The amount by which the gross deferred tax assets exceed the estimate of future taxable income will be charged to net income, however these amounts can be reversed in future periods if future taxable income increases.

We recorded an impairment of $994.8 million (Canadian cost centre: $134.4 million, U.S. cost centre $860.4 million) on our crude oil and natural gas assets in 2020. There were no crude oil and natural gas assets impairments recorded in 2019 and 2018. In 2020, we reversed our valuation allowance of $13.9 million recorded in 2019 against a portion of our Canadian deferred income tax asset, as projected future taxable income in Canada was sufficient to recognize these assets. No valuation allowance was recorded against our U.S. deferred income tax asset. There is a risk of impairment on our oil and gas properties, deferred tax asset and goodwill if commodity prices weaken, costs increase, or if there is a downward revision to reserves. Please refer to the “Impairments” and “Income Taxes” sections of the MD&A and Notes 5 and 13 of the Financial Statements for further details.

Changes in Income Tax and Other Laws

Income tax, other laws or government incentive programs relating to the oil and gas industry may change in a manner that adversely affects us or our security holders. Canadian, U.S. and foreign tax authorities may interpret applicable tax laws, tax treaties or administrative positions differently than we do or may disagree with how we calculate our income for tax purposes in a manner which is detrimental to us and our security holders.

We monitor developments with respect to pending legal changes and work with the industry and professional groups to ensure that our concerns with any changes are made known to various government agencies. We obtain confirmation from independent legal counsel and advisors with respect to the interpretation and reporting of material transactions.

Counterparty and Joint Venture Credit Exposure

We are subject to the risk that the counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements as a result of liquidity requirements or insolvency. Low crude oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure of our counterparties to perform their financial or operational obligations may adversely affect our operations and financial position. In addition to the usual delays in payment by purchasers of crude oil and natural gas, payments may also be delayed by, among other things: (i) capital or liquidity constraints experienced by our counterparties, 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 our cash flow and the payment of cash dividends to our shareholders in a given period and expose us to additional third-party credit risks.

A credit review process is in place to assess and monitor our counterparties’ credit worthiness on a regular basis. This includes reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted we attempt to obtain financial assurances such as letters of credit, parental guarantees, or third-party insurance to mitigate our counterparty risk. In addition, we monitor our receivables against a watch list of publicly traded companies that have high debt-to-cash flow ratios or fully drawn bank facilities and, where possible, take our production in kind rather than relying on third party operators. In certain instances, we may be able to aggregate all amounts owing to each other and settle with a single net amount.

See the “Liquidity and Capital Resources” section for further information.

Debt covenants may be exceeded with no ability to negotiate covenant relief

Declines or continued volatility in crude oil and natural gas prices may result in a significant reduction in earnings or cash flow, which could lead us to increase amounts drawn under our bank credit facility in order to carry out our operations and fulfill our obligations. Significant reductions to cash flow, significant increases in drawn amounts under the bank credit facility, or significant reductions to proved reserves may result in us breaching our debt covenants under the credit facility, senior notes and Term Facility. If a breach occurs, there is a risk that we may not be able to negotiate covenant relief with one or more of our lenders under the credit facility, senior notes or Term Facility. Failure to comply with debt covenants, or negotiate relief, may result in our indebtedness under the credit facility, senior notes or Term Facility becoming immediately due and payable, which may have a material adverse effect on our operations and financial condition.

ENERPLUS 2020 FINANCIAL SUMMARY 33

The credit facility, senior notes, Term Facility and any replacement credit facility may not provide sufficient liquidity

Although we believe that our existing credit facility, senior notes and the recently added Term Facility are sufficient, there can be no assurance that the current amount will continue to be available, or will be adequate for our financial obligations, or that additional funds can be obtained as required or on terms which are economically advantageous to Enerplus. The amounts available under the credit facility, senior notes and Term Facility may not be sufficient for future operations, or we may not be able to renew our bank credit facility or Term Facility or obtain additional financing on attractive economic terms, if at all. The Term Facility matures in early 2024 (three years post-closing date of the Bruin Acquisition). The bank credit facility is generally available on a four-year term, extendable each year with a bullet payment required at the end of four years if the facility is not renewed. We renewed our bank credit facility in 2019 and it currently expires on October 31, 2023. There can be no assurance that such a renewal will be available on favourable terms or that all the current lenders under the facility will participate or renew at their current commitment levels. If this occurs, we 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 by Enerplus to obtain replacement financing or financing on favourable terms, may have a material adverse effect on our business and operations. In addition, dividends to shareholders may be eliminated, as repayment of debt under the credit facility, senior notes and Term Facility has priority over dividend payments to our shareholders.

Access to Field Services

Our ability to drill, complete and tie-in wells in a timely manner may be impacted by our access to service providers and supplies. Activity levels in each area may limit our access to these resources, restricting our ability to execute our capital plans in a timely manner. In addition, field service costs are influenced by market conditions and therefore can become cost prohibitive.

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services through 2021, access to field services and supplies in other areas of our business will continue to be subject to market availability.

Cyber Security Risks

We are subject to a variety of information technology and system risks as part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach and destruction or interruption of our information technology systems by third parties or insiders. Additionally, use of personal devices can create further avenues for potential cyber-related incidents, as we have little or no control over the safety of these devices. Information technology and cyber risks have increased during the COVID-19 pandemic, as increased malicious activities are creating more threats for cyberattacks including COVID-19 phishing emails, malware-embedded mobile apps that purport to track infection rates, and targeting of vulnerabilities in remote access platforms as many companies continue to operate with work from home arrangements. Although we have security measures and controls in place that are designed to mitigate these risks, a breach of our security and/or a loss of information could occur and result in business interruptions, service disruptions, financial loss, theft of intellectual property and confidential information, litigation, enhanced regulatory attention and penalties, as well as reputational damage. Furthermore, the adoption of emerging technologies, such as cloud computing, artificial intelligence and robotics, call for continued focus and investment to manage risks effectively. Not managing this risk effectively may have an adverse effect and, therefore, may increase the risk of financial or reputational loss. The significance of any such event is difficult to quantify, but may be material in certain circumstances and could have a material effect on our business, financial condition and results of operations.

Ability to Divest Properties

Regulatory changes in Alberta and Saskatchewan have increased the minimum corporate liability rating required of purchasers of crude oil and natural gas properties. As a result, the potential number of parties able to acquire our non-core assets has been reduced, we may not be able to obtain full value for such assets, or transactions may involve greater risk and complexity. The Supreme Court of Canada’s decision in the Redwater Energy Corporation case may also impact our ability to transfer licenses, approvals or permits, and may result in increased costs and delays or require changes to our abandonment of projects and transactions. We also understand that further regulatory changes are being planned in Alberta and British Columbia, which may result in additional factors being considered when evaluating such transactions.

Title Defects or Litigation

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

Although we conduct title reviews prior to the purchase of assets these reviews do not guarantee that an unforeseen defect in the chain of title will not arise. We maintain good working relationships with our industry partners; however, disputes may arise from time to time with respect to ownership of rights of certain properties or resources.

34 ENERPLUS 2020 FINANCIAL SUMMARY

Foreign Currency Exposure

We have exposure to fluctuations in foreign currency as all of our senior notes, our credit facility and our Term Facility are denominated in U.S. dollars. Our U.S. operations are directly exposed to fluctuations in the U.S. dollar when translated to our Canadian dollar denominated financial statements. We also have indirect exposure to fluctuations in foreign currency as our crude oil sales and a portion of our natural gas sales are based on U.S. dollar indices. Our oil and gas revenues are positively impacted when the Canadian dollar weakens relative to the U.S. dollar. However, our U.S. capital spending, transportation and operating costs, interest expense and U.S. dollar denominated debt are negatively impacted with a weak Canadian dollar.

Currently, we do not have any foreign exchange contracts in place to hedge our foreign exchange exposure. However, we continue to monitor fluctuations in foreign exchange and the impact on our operations.

Interest Rate Exposure

Movements in interest rates and credit markets may affect our borrowing costs and value of investments such as our shares as well as other equity investments.

At December 31, 2020, we were undrawn on our US$600 million bank credit facility and our debt consisted of fixed interest rate senior notes.

On January 25, 2021, we entered into the Purchase Agreement to acquire all the equity interests of Bruin for total cash consideration of US$465 million, subject to certain adjustments. On the same date, we entered into a new three-year, senior unsecured US$400 million Term Facility, to be fully drawn down on the closing date of the Bruin Acquisition to pay for a portion of the purchase price. The Term Facility includes financial and other covenants and pricing consistent with our existing US$600 million revolving credit facility, which matures October 31, 2023. Funding under the Term Facility is subject to limited conditions, including completion of the acquisition and delivery of customary credit facility documentation.

ADJUSTED FUNDS FLOW SENSITIVITY

The sensitivities below reflect all of Enerplus’ commodity contracts listed in Note 15 to the Financial Statements and are based on 2021 guidance production, assuming the successful closing of the Bruin Acquisition in early March, and price levels of: WTI - US$55.00/bbl, NYMEX - US$3.00/Mcf and a USD/CDN exchange rate of 1.27. To the extent crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.


	Estimated Effect on 2021
Sensitivity Table	Adjusted Funds Flow per Share⁽¹⁾
Increase of US$5.00 per barrel in the price of WTI crude oil	$	0.26
Decrease of US$5.00 per barrel in the price of WTI crude oil	$	(0.32)
Increase of US$0.50 per Mcf in the price of NYMEX natural gas	$	0.12
Decrease of US$0.50 per Mcf in the price of NYMEX natural gas	$	(0.12)
Change of 1,000 BOE/day in production	$	0.03
Change of $0.01 in the US/CDN exchange rate	$	0.02
Change of 1% in interest rate⁽²⁾	$	0.02

(1)	Calculated using 256.2 million shares outstanding at February 18, 2021.

(2)	The interest rate sensitivity reflects the Term Facility, which will be fully drawn upon closing of the Bruin Acquisition. Enerplus is currently undrawn on its floating interest rate bank credit facility and all outstanding senior notes are based on fixed interest rates.

2021 GUIDANCE⁽¹⁾


Summary of 2021 Annual Expectations		Target
Capital spending		$335 - $385 million
Average annual production		103,500 – 108,500 BOE/day
Average annual crude oil and natural gas liquids production		63,000 – 67,000 bbls/day

2021 Differential/Basis Outlook⁽²⁾		Target
Average U.S. Bakken crude oil differential (compared to WTI crude oil)		US$(3.25)/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)		US$(0.55)/Mcf

(1)	Guidance is based on the continued operation of DAPL, the completion of the Bruin Acquisition at the beginning of March 2021 and a ten-month contribution from the Bruin assets.

(2)	Excludes transportation costs

NON-GAAP MEASURES

The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and therefore may not be comparable with the calculation of similar measures by other entities:

ENERPLUS 2020 FINANCIAL SUMMARY 35

“Netback” is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of our crude oil and natural gas assets. Netback is calculated as crude oil and natural gas sales less royalties, production taxes, operating expenses and transportation costs.


Calculation of Netback	Year ended December 31,
($ millions)		2020		2019		2018
Crude oil and natural gas sales, net of royalties		$	737.2	$	1,254.8	$	1,292.7
Less:
Production taxes			(49.9)		(83.1)		(87.3)
Operating expenses			(263.6)		(290.8)		(238.3)
Transportation costs			(132.4)		(144.9)		(123.5)
Netback before hedging		$	291.3	$	736.0	$	843.6
Cash gains/(losses) on derivative instruments			131.0		15.4		(35.8)
Netback after hedging		$	422.3	$	751.4	$	807.8

“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.


Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow	Year ended December 31,
($ millions)		2020		2019		2018
Cash flow from operating activities		$	446.4	$	694.2	$	738.8
Asset retirement obligation expenditures			17.7		16.7		11.3
Changes in non-cash operating working capital			(105.9)		(1.9)		3.4
Adjusted funds flow		$	358.2	$	709.0	$	753.5

“Free cash flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Free cash flow is calculated as adjusted funds flow minus capital spending.


Calculation of Free Cash Flow	Year ended December 31,
($ millions)		2020		2019		2018
Adjusted funds flow		$	358.2	$	709.0	$	753.5
Capital spending			(291.4)		(618.9)		(593.9)
Free cash flow		$	66.8	$	90.1	$	159.6

“Adjusted net income” is used by Enerplus and is useful to investors and securities analysts in evaluating the financial performance of the company by understanding the impact of certain non-cash items and other items that the Company considers appropriate to adjust given the irregular nature and relevance to comparable companies. Adjusted net income is calculated as net income adjusted for unrealized derivative instrument gain/loss, asset impairments, unrealized foreign exchange gain/loss, the tax effect of these items, goodwill impairment, the impact of statutory changes to the Company’s corporate tax rate and the valuation allowance on our deferred income tax assets. Adjusted net income in 2020 included adjustments related to asset impairments and the valuation allowance on deferred taxes. No asset impairments or valuation allowance on deferred taxes were recorded in 2019 or 2018.


Calculation of Adjusted Net Income	Year ended December 31,
($ millions)		2020		2019		2018
Net income/(loss)		$	(923.4)	$	(259.7)	$	378.3
Unrealized derivative instrument (gain)/loss			23.6		81.7		(124.3)
Asset impairment			994.8		—		—
Unrealized foreign exchange (gain)/loss			1.9		(34.1)		58.6
Tax effect on above items			(266.0)		(18.5)		32.2
Goodwill impairment			202.8		451.1		—
Income tax rate adjustment on deferred taxes			—		22.7		—
Valuation allowance on deferred taxes			(13.9)		—		—
Adjusted net income		$	19.8	$	243.2	$	344.8

“Total debt net of cash” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. Total debt net of cash is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and cash equivalents.

36 ENERPLUS 2020 FINANCIAL SUMMARY

“Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash divided by a trailing twelve months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depletion, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) and is not a debt covenant.

“Adjusted payout ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. We calculate our adjusted payout ratio as cash dividends plus capital spending, office expenditures and line fill divided by adjusted funds flow.


Calculation of Adjusted Payout Ratio	Year ended December 31,
($ millions)		2020		2019		2018
Cash dividends		$	26.7	$	27.7	$	29.3
Capital, office expenditures and line fill			295.7		629.8		600.4
Sub-total		$	322.4	$	657.5	$	629.7
Adjusted funds flow		$	358.2	$	709.0	$	753.5
Adjusted payout ratio (%)			90%		93%		84%

“Adjusted EBITDA” is used by Enerplus and its lenders to determine compliance with financial covenants under its bank credit facility and outstanding senior notes.


Reconciliation of Net Income to Adjusted EBITDA⁽¹⁾
($ millions)	December 31, 2020
Net income/(loss)	$	(923.4)
Add:
Asset impairment		994.8
Goodwill impairment		202.8
Interest		28.4
Current and deferred tax expense/(recovery)		(260.8)
DD&A		293.2
Other non-cash charges⁽²⁾		38.1
Adjusted EBITDA	$	373.1

(1)	Adjusted EBITDA is calculated based on the trailing four quarters.

(2)	Includes the change in fair value of commodity derivatives, equity swaps, non-cash SBC expense, and unrealized foreign exchange gains/losses.

In addition, the Company uses certain financial measures within the “Overview” and “Liquidity and Capital Resources” sections of this MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include “senior debt to adjusted EBITDA”, “senior net debt to adjusted EBITDA”, “total debt to adjusted EBITDA”, “total debt to capitalization”, “senior debt to consolidated present value of total proved reserves” and “adjusted EBITDA to interest” and are used to determine the Company’s compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of such terms is described under the “Liquidity and Capital Resources” section of this MD&A.

INTERNAL CONTROLS AND PROCEDURES

Internal Controls over Financial Reporting

We maintain internal controls over financial reporting that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Management is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rule 13a – 15(f) and 15d – 15(f) under the U.S. Securities Exchange Act of 1934, as amended (the Exchange Act) and under National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (NI 51-109). Management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of Enerplus Corporation, have conducted an evaluation of our internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013). Based on management’s assessment as of December 31, 2020, management has concluded that our internal controls over financial reporting is effective.

The effectiveness of internal controls over financial reporting as of December 31, 2020 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm, which is included with the annual financial statements.

ENERPLUS 2020 FINANCIAL SUMMARY 37

Due to its inherent limitations, internal controls over financial reporting is not intended to provide absolute assurance that a misstatement of our financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal

control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

Changes in Internal Controls over Financial Reporting

There were no changes in our internal control over financial reporting in 2020 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in our interim and annual filings is reviewed, recognized and disclosed accurately and in the appropriate time period. Management, including the CEO and CFO, carried out an evaluation, as of December 31, 2020, of the effectiveness of the design and operation of disclosure controls and procedures of Enerplus, as defined in Rule 13a – 15(e) and 15d – 15(e) under the Exchange Act and NI 52-109. Based on that evaluation, the CEO and CFO have concluded that the design and operation of disclosure controls and procedures at Enerplus were effective to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act or Canadian securities legislation is recorded, processed, summarized and reported within the time periods specified in the rules and forms therein.

It should be noted that while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that these disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

ADDITIONAL INFORMATION

Additional information relating to Enerplus, including our current Annual Information Form, is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.

38 ENERPLUS 2020 FINANCIAL SUMMARY

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "ongoing", "may", "will", "project", "plans", “budget”, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: the continued uncertainty regarding timing and impact of COVID-19, expected 2021 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; anticipated production volumes subject to curtailment; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials and our commodity risk management program in 2021 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2021 and impact thereof on our production levels and land holdings; potential future asset impairments, as well as relevant factors that may affect such impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements, including the entering into of Term Facility; expectations regarding our ability to comply with debt covenants under our bank credit facility and outstanding senior notes; our future acquisitions and dispositions including the Bruin Acquisition and the completion, timing and anticipated benefits thereof; the impact of the Bruin Acquisition on Enerplus’ operations, reserves, inventory and opportunities, financial condition and overall strategy; expecting timing thereof and use of proceeds therefrom; the amount of future cash dividends that we may pay to our shareholders, and our ESG initiatives, including GHG emissions and water reduction targets for 2021.

The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated, including the continued operation of DAPL; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; the satisfaction of the conditions to close the Bruin Acquisition and the Term Facility; the availability of third party services; the extent of our liabilities; and the availability of technology and process to achieve environmental targets. In addition, our 2021 guidance contained in this MD&A is based on the following: the completion of the Bruin Acquisition in the timeframe currently contemplated; and a WTI price of US$55.00/bbl, a NYMEX price of US$3.00/Mcf, a Bakken crude oil price differential of US$3.25/bbl below WTI and a USD/CDN exchange rate of 1.27. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this MD&A is not a guarantee of future performance and should not be unduly relied upon. Such information involves 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 including, without limitation: continued low commodity prices environment or further volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors, reliance on industry partners and third party service providers; failure to complete the Bruin Acquisition in accordance with its terms or at all and failure to realize the anticipated benefits of the Bruin Acquisition; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F as at December 31, 2020).

The purpose of our adjusted funds flow sensitivity is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

ENERPLUS 2020 FINANCIAL SUMMARY 39

EXHIBIT 99.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use of our reports, each dated February 19, 2021, with respect to the consolidated balance sheets of Enerplus Corporation as at December 31, 2020 and December 31, 2019, the consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2020, and the effectiveness of internal control over financial reporting as of December 31, 2020 included in this annual report on Form 40-F.

We also consent to the incorporation by reference of such reports in the Registration Statements (No. 333-200583) on Form S-8 and the Registration Statements (No. 333-216844) on Form-10.


	/s/ KPMG LLP
	Chartered Professional Accountants

Calgary, Canada

February 19, 2021

EXHIBIT 99.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of our name in the Annual Report on Form 40-F (the "Annual Report") of Enerplus Corporation (the "Registrant"). We hereby further consent to the inclusion in the Annual Report of the Registrant's Annual Information Form dated February 19, 2021 for the year ended December 31, 2020, which document makes reference to our firm and our reports dated February 9, 2021, evaluating the Registrant's oil, natural gas and natural gas liquids interests effective December 31, 2020.


Calgary, Alberta, Canada February 17, 2021	MCDANIEL & ASSOCIATES CONSULTANTS LTD.

	/s/ Brian Hamm
	Brian Hamm, P.Eng.
	President & CEO

EXHIBIT 99.6

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of our name in the Annual Report on Form 40-F (the "Annual Report") of Enerplus Corporation (the "Registrant"). We hereby further consent to the inclusion in the Annual Report of the Registrant's Annual Information Form dated February 19, 2021, for the year ended December 31, 2020, which document makes reference to our firm and our report dated February 16, 2021, evaluating the Registrant's shale gas and contingent resources interests effective December 31, 2020.


Dallas, Texas February 17, 2021	NETHERLAND, SEWELL & ASSOCIATES, INC.

By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

EXHIBIT 99.7

CERTIFICATION

I, Ian C. Dundas, certify that:

1.	I have reviewed this Annual Report on Form 40-F of Enerplus Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.


Date: February 19, 2021	/s/ Ian C. Dundas
	Ian C. Dundas
	President and Chief Executive Officer
	of Enerplus Corporation

EXHIBIT 99.8

CERTIFICATION

I, Jodine J. Jenson Labrie, certify that:

1.	I have reviewed this Annual Report on Form 40-F of Enerplus Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 19, 2021

/s/ Jodine J. Jenson Labrie

Jodine J. Jenson Labrie

Senior Vice President and

Chief Financial Officer of Enerplus Corporation

EXHIBIT 99.9

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Enerplus Corporation (the “Corporation”) on Form 40-F for the fiscal year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ian C. Dundas, President and Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

President and Chief Executive Officer of Enerplus Corporation
/s/ Ian C. Dundas
Ian C. Dundas President and Chief Executive Officer of Enerplus Corporation

February 19, 2021

The foregoing certification shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of that section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.

EXHIBIT 99.10

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Enerplus Corporation (the “Corporation”) on Form 40-F for the fiscal year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jodine J. Jenson Labrie, Senior Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

Senior Vice President and Chief Financial Officer of Enerplus Corporation
/s/ Jodine J. Jenson Labrie
Jodine J. Jenson Labrie Senior Vice President and Chief Financial Officer of Enerplus Corporation

February 19, 2021

EXHIBIT 99.11

CODE OF BUSINESS CONDUCT

The Code of Business Conduct is our guide to ethical and lawful conduct in our daily business. It requires all of us, from members of our board of directors to new hires, to adhere to a level of ethical business conduct well in excess of the legal minimum. Our compliance with both the letter and spirit of the Code of Business Conduct is essential to protecting Enerplus’ business and reputation.

INTRODUCTION

Enerplus’ Commitment

Enerplus Corporation and all of its affiliates (“Enerplus” or the “Corporation”) are committed to maintaining the highest of business standards in our operations, wherever they may be. We recognize the importance of credibility, integrity, and trust to our success as a business.

Purpose and Applicability of the Code

This Code of Business Conduct summarizes a number of Enerplus policies for appropriate behaviour and applies to all employees, consultants, officers and directors of Enerplus (hereinafter, “Employees”). Accordingly, each of us must comply with the terms of this Code. The Code will help us meet our business practice standards and comply with applicable laws and regulations. It is essential that this Code of Business Conduct be observed. The Code is very important to protecting Enerplus’ business and reputation.

The Code of Business Conduct is a general guideline for making certain that:

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A work environment is maintained that promotes the dignity and self-respect of each Employee.

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All Employees are aware of and fully observe the laws and regulations that impact their business activities.

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A standard of behaviour is in place that reflects the values and integrity of Enerplus and its Employees.

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Enerplus is protected from financial loss and legal liability.

This Code of Business Conduct does not replace any other published rules and policies of Enerplus, including other guidelines and personal conduct policies. All Enerplus policies and standards are subject to this Code. While this Code of Business Conduct provides guidance and explains what is considered unacceptable behaviour, the Code of Business Conduct does not describe every specific act that is unacceptable. If a specific act is missing from the Code, it does not mean that act is acceptable or condoned. Ultimately, we must rely on our judgment about the right thing to do in order to maintain our personal and corporate integrity.

The Code is to be used as a guide for appropriate conduct and to prevent improper conduct. Enerplus will not tolerate any conduct that is unlawful or damaging to Enerplus’ reputation.

Employee Responsibilities

All Employees are responsible for reading this entire Code of Business Conduct and ensuring their conduct is consistent with both the letter and the spirit of Enerplus’ business practices.

This Code will help Employees deal with specific situations. In some cases, a situation may be so complex or circumstances so unique that additional guidance is needed. If such a situation occurs and is not included in this Code, it is each Employee’s duty to contact his/her supervisor or the People & Culture Department immediately. If necessary, the People & Culture Department may refer the matter to the Legal Department for further advice.

This Code and any detailed Enerplus policy statements and procedures will be updated from time to time. All Employees are required to stay informed of any updates and to comply with all requirements. All Enerplus policies can be located under the “How We Work” section of the internal website.

Management Responsibilities

Managers must exhibit the highest standards of corporate responsibility and business conduct and create a work atmosphere that supports our corporate values and policies, including this Code. It is the duty of each member of management to take into account an Employee’s willingness and commitment to comply with this Code when making promotion and other employment decisions.

Compliance Requirements

Employees must work honestly and in good faith. Employment with Enerplus depends upon an Employee’s ability and willingness to comply with this Code. Adherence to these standards carries the highest priority. All Employees are required to acknowledge compliance when they are hired and again on an annual basis.

GLOBAL BUSINESS CONDUCT GUIDELINES

Our Employees

Discrimination, Bullying and Workplace Harassment

Employees are forbidden to discriminate against, bully or harass other Employees, in keeping with our Harassment Policy. No Employee is permitted to act in a way that is considered or could be considered illegal or harassing.

It is the responsibility of each member of management to be diligent in recognizing and responding to any behaviour or conduct that could be considered workplace harassment, bullying or discrimination. Management also is required to apply our policies and immediately contact the People & Culture Department regarding any situation that could be considered workplace harassment, bullying or discrimination.

It is the responsibility of each Employee to maintain a work environment free of discrimination, bullying and harassment and to report any situation that the Employee believes may be workplace harassment, bullying or discrimination to his/her supervisor, department head or the People & Culture Department.

Employment of Family Members

Enerplus allows an Employee’s spouse, parents, children, and other family members to work for Enerplus, both during and after the employee’s career with Enerplus, provided the employment is in Enerplus’ best interest. Family relationships, however, will not be considered in hiring decisions. All Enerplus hiring decisions will be made strictly on the basis of individual qualifications. To avoid the possibility or appearance of preferential treatment, Enerplus will not have one family member placed in a position of influence over another family member.

Workplace Health and Safety

The health and safety of our personnel and the safe operation of our facilities are principal objectives of Enerplus. We are committed to providing safe and healthy places of employment and will follow operating practices that eliminate or minimize exposure to hazardous or unhealthy conditions. The success of our health and safety efforts depends upon the cooperation, support, and active involvement of all Enerplus personnel. From time to time, Enerplus will implement specific and extraordinary safety and health protocols, rules and restrictions to ensure a safe and healthy work environment for all Enerplus personnel. The 2020 Covid health crisis is an example. Each Employee is responsible for working safely and complying with all safety rules and protocols at all times.

In addition, we are committed to maintaining a safe and secure work environment. Threats, intimidation, harassment, assaults, and acts of violence are unacceptable and will not be tolerated.

Employees should refer to the How We Work section of the internal website for our Environmental, Social and Governance (ESG) Policy and minimum safety standards. Questions or concerns should be reported immediately to a supervisor, the Corporate Sustainability Department or the People & Culture Department.

Prohibited Items

The use, sale, possession or distribution of illegal drugs, or the improper use of alcohol or prescription drugs, by Employees is strictly forbidden while on Enerplus premises, in Enerplus vehicles, or while conducting Enerplus business on or off Enerplus premises. The use of alcohol is prohibited to the extent that it has a detrimental effect on job performance, safety, or efficiency while conducting Enerplus business on or off Enerplus premises. The approval of an Enerplus officer is required to consume or possess alcoholic beverages on Enerplus premises. Consumption of alcohol in Enerplus owned or leased vehicles or personal vehicles used for Enerplus business is strictly prohibited, and possession is permitted only in accordance with the Alcohol and Drug Policy. For further information, please refer to the Alcohol and Drug Policy.

The possession, use, or distribution of firearms, weapons, and explosives is prohibited while on Enerplus premises, while conducting Enerplus business, or while in Enerplus vehicles on or off Enerplus premises, except as authorized under the Firearm Storage, Transportation and Use Standard found on the S&SR Management System, located under the Owning Zero section of the internal website.

If evidence supports a reasonable suspicion of use, possession, or distribution of prohibited items, Enerplus reserves the right to conduct searches on Enerplus premises or in Enerplus owned or leased vehicles for such items.

Our Company

Document Retention

Employees must comply with Enerplus’ department-specific document (physical and electronic) retention guidelines to ensure that all applicable laws and regulations are met. Each Employee should become familiar with and adhere to these guidelines. Additionally, when litigation or an investigation is pending, Employees are prohibited from modifying or destroying relevant documents or records, including Employees’ personal files and electronic records. The consequences of modifying or destroying any relevant documents or records are severe and may include prosecution. An Employee who has any doubt about the legality or propriety of modifying or destroying any document or record should contact his/her supervisor or General Counsel before proceeding.

External Communications

From time to time, Employees may be contacted by government representatives or legal counsel representing other companies, government agencies, or individuals in connection with investigations that concern Enerplus, its business, counterparties, Employees, or suppliers. While Enerplus cooperates with all reasonable requests from government agencies and authorities related to Enerplus’ business, an Employee receiving a request for information other than what is provided on a routine basis should decline to respond and immediately report the request to his/her supervisor and seek guidance from the Legal Department. Likewise, if an Employee receives a subpoena or other request to testify or produce documents in relation to Enerplus’ business, a copy of the subpoena or request should be forwarded immediately to our General Counsel. All information provided should be truthful and accurate. Employees must never mislead any investigator and must never modify or destroy documents or records in response to an investigation.

Disclosure of Corporate Information; Trading Restrictions

Employees must not trade Enerplus securities while in possession of material, non-public corporate information. Employees must not use such material, non-public corporate information for their benefit or the benefit of others. Material corporate information is any information that, if known, might influence a reasonable investor’s investment decision to buy, sell, or hold securities of Enerplus. Non-public means any corporate information that has not been released by Enerplus for public dissemination and which is intended to remain confidential until such authorized dissemination. With the exception of disclosure to Enerplus’ advisors, Employees should not share material, non-public corporate information with anyone outside Enerplus (including family members) until it has been made public, regardless of how the information may or may not be used. These restrictions also apply to trading in securities of any other company (including, but not limited to, competitors, suppliers, and counterparties) if an Employee learns of any material, non-public information about that company during the course of his/her employment with Enerplus.

Employees must adhere to blackout restrictions posted on published blackout calendars. Trading blackouts are implemented to ensure that “insiders” do not have the advantage of information that has not been announced to the general investing public. “Insiders” are considered to be anyone who has access to information that has not been released to the public realm. Applicable securities laws dictate the protection of the entire investing public to ensure fairness. Should an individual breach insider trading rules they may be subject to significant penalties by regulatory authorities.

Announcements of material information will include scheduled and unscheduled announcements. Scheduled announcements include the release of quarterly financial statements, annual financial statements and annual reports of Enerplus, and in that regard, trading in Enerplus securities by Employees will be prohibited for a certain time before and after the release of financial statements. Unscheduled announcements may include the release of information relative to changes in the Corporation of a financial or structural nature, which may or may not require trading blackouts.

Management will make every attempt to inform Employees of changes to blackout periods. However, blackout periods may change without notice. Should you have any questions or require clarification regarding trading restrictions, it is your responsibility to direct these questions to General Counsel prior to trading any Enerplus securities.

Employees must report violations or misuse of material, non-public corporate information to our General Counsel immediately.

Directors and officers of Enerplus are required by securities regulations to make certain filings with securities commissions to report their holdings and transactions in Enerplus’ securities. Questions about these laws should be directed to the General Counsel.

Directors and other Employees of Enerplus may not, directly or indirectly, buy, sell or enter into:

•

any short sale of securities of Enerplus;

•

any puts, call options or other rights or obligations to buy or sell securities of Enerplus;

•

any derivative instruments, agreements or securities, the market price, value or payment obligations of which are derived from or based on the value of securities of Enerplus; or

•

any other derivative instruments, agreements, arrangements or understandings (commonly known as equity monetization transactions), the effect of which is to alter, directly or indirectly, a director’s or other Employee’s economic interest in securities of Enerplus, with the exception of corporate equity hedges or normal course issuer bids.

Enerplus believes that the interests of the Corporation’s directors, officers and other Employees should be aligned with those of the Corporation’s other shareholders. Engaging in the above activity frustrates our intention that directors and officers hold a meaningful ownership interest in Enerplus and bear the full risks and rewards of ownership.

Conflicts of Interest

Employees are not permitted to do anything that does not support the best interests of Enerplus. For example:

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An Employee should not use Enerplus property for his/her own material benefit.

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An Employee should not influence Enerplus’ contractors or consultants for his/her own personal gain.

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An Employee, or his/her family members or friends, should not act on business opportunities or investments presented to Enerplus, other than for the benefit of the Corporation, that are not available to the public, without written permission from General Counsel.

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An Employee should not make or recommend decisions for Enerplus that might benefit the Employee, his/her family members, or friends financially.

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An Employee or their spouse should not own a five percent (5%) or more equity interest in any entity that sells supplies, furnishes services, or otherwise does business with Enerplus without written permission from General Counsel.

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An Employee or their spouse should not own a five percent (5%) or more equity interest in any entity that is a competitor of Enerplus without disclosing such interest.

Before acknowledging compliance with this Code, an Employee must report in writing any conflicts of interest to the People & Culture Department. If conflicts of interest arise after the Employee has acknowledged compliance, the Employee must report the conflicts immediately in writing to the People & Culture Department, which will disclose such conflicts to General Counsel.

During regular business hours, Employees should devote their full time and attention to Enerplus and their assigned job duties unless they have received permission from their leader. Unrelated outside activities, business, or secondary employment are not permitted during regular business hours except as provided above.

With the exception of Enerplus directors, no Employee of Enerplus should serve on the executive or board of any corporation that Enerplus does not control or have an ownership interest in without the written approval of Enerplus’ General Counsel. It is acceptable to serve on the board of a non-profit, charitable, religious, or civic organization without prior written approval, provided it does not interfere with or impair the Employee’s ability to perform their duties at Enerplus and represents a commitment of personal time.

To avoid potential conflicts of interest, it is against Enerplus’ policy for Enerplus to extend loans to officers or directors.

Confidential and Proprietary Information

Occasionally, Employees may know confidential information concerning Enerplus’ business, including counterparties, suppliers, business contacts, Employees, or technical operations. Employees must keep this information confidential during and after their employment with Enerplus. Personal information relating to Enerplus counterparties, suppliers, business contacts or Employees must be treated in accordance with Enerplus' Privacy Policy.

Generally, any information stored by and/or processed by Enerplus is proprietary information. This confidential information includes computerized data, methods, techniques, and documentation relating to Enerplus’ computing services, developed software, and third-party software.

Employees must be aware of their responsibilities regarding access to Enerplus’ computer services, and the access, use, and disclosure of confidential information. Confidential and proprietary information must be used for Enerplus

purposes only, never for personal gain. Enerplus prohibits Employees from releasing or misusing any confidential and proprietary Enerplus information.

Accounting and Reporting

Accurate documents are important during audits and other internal or external reviews. All Employees must comply with Enerplus’ accounting and reporting procedures and make sure all books, records, accounts, and supporting papers are accurate and complete. Employees are forbidden to forge, falsify, or intentionally leave out important facts on any business documents of Enerplus which could mislead auditors or other internal or external reviewers.

Expense Accounts

Employee expense accounts are to be used only to reimburse Employees for items and activities that are purchased for Enerplus business. Employees must submit accurate expense reports of the money spent for this purpose. Where expenses are incurred in the presence of other Employees, the Employee with the most seniority should make the payment.

Enerplus’ Information Technology Resources

Corporate information, information systems and electronic communications are considered assets and valuable resources to Enerplus. Enerplus requires the appropriate use of these assets and their protection in a manner commensurate with their sensitivity, value and criticality. Any electronic communication of personal information must be in accordance with Enerplus’ Privacy Policy.

All Employees are required to:

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Manage and protect corporate information, information systems and electronic communications in accordance with all Enerplus policies, standards and procedures, including statutory and regulatory requirements;

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Take accountability for appropriate security, access and retention of specific information they are responsible for; and

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Report incidents and assist in investigations relating to the misuse of information assets.

Enerplus’ information technology resources, such as email and internet access, are provided to Employees in pursuit of Enerplus’ business. While limited personal use of these resources is acceptable, Employees should not expect their use of these resources to be private or confidential. Personal use of these resources, such as accessing social networking/media websites (e.g. Facebook, Instagram, Twitter, YouTube, etc.), also should not interfere with Employee productivity or business processes.

Employees should take the same care in their electronic communications as they take when they communicate in person or by paper. Information and data are at risk when transmitted over the internet.

Employees shall not use Enerplus’ information technology resources inappropriately, including the following prohibited activities:

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Accessing, viewing, downloading, storing or redistributing any material or message that is illegal or offensive

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Activities designed to evade, compromise or otherwise exploit security controls

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Possession or use of assessment and discovery tools that could be used to collect information to compromise the security of Enerplus’ information system or launch attacks against other parties’ information systems;

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The intentional creation and/or transmission of malicious code (viruses, worms, etc.);

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Malicious activity including, but not limited to: erasing, renaming or making unusable any software, data or information;

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Disclosing, gathering or using another Employee’s account/password to access any information technology resources;

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Participation in chain letters or other forms of mass mailing or marketing; or

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Connecting non-Enerplus/personal devices (laptops, external hard/flash drives, etc.) directly to an Enerplus device or network unless authorized by the Information Services Department.

Enerplus does not allow Employees to copy or distribute copyrighted materials (e.g., software, database files, articles, graphics, music, movies, etc.) through Enerplus’ email system or by any other means without confirming in advance from appropriate sources that Enerplus has the right to copy or distribute the material. Employees are not permitted to install any software on Enerplus’ information systems without the express written consent of an executive with responsibility for the Information Services Department.

An Employee’s logon IDs and passwords are intended for his/her use only and each Employee is responsible for all activity that occurs under their accounts. Employees must protect their accounts through the use of strong passwords.

Enerplus may access its information technology resources at any time as part of an internal audit or to investigate suspected unauthorized use, and may disclose the information it accesses to law enforcement or other third parties without prior consent of the sender or the recipient.

Employees should consult the Information Assets Security Policy and the Information Services Security section of the internal website for further information regarding security standards, guidelines and awareness.

Internet/Intranet Site Development

Enerplus’ internet and intranet are important platforms to communicate Enerplus information to Employees, counterparties, and the public.

As such, the Corporation’s Information Services Department and the People & Culture Department shall be solely responsible for and shall administer the creation and development of all Enerplus internet and intranet sites. From time to time and based on business need, access to internet or intranet pages may be granted to Employees for creation or revision of content. Employee and stakeholder suggestions for enhancement to the sites are encouraged.

Corporate Logo

The logos of Enerplus and its business units are considered property of Enerplus and must only be used for business purposes. Only the approved logos, which are available through the People & Culture Department and the intranet, may be used, and approval must be obtained prior to using any Enerplus logo on materials to be distributed outside of Enerplus. Re-creation or alteration of Enerplus’ logos is not permitted. Acquisition of all logo items, such as apparel and office items, must be coordinated through the Stakeholder Engagement, Corporate Sustainability or Investor Relations teams.

Our Business Partners and Counterparties

Relationships with Contractors and Suppliers

Contractor and supplier relationships must be managed in a fair, equitable, and ethical manner consistent with this Code of Business Conduct, all applicable laws, and good business practices.

Enerplus promotes competitive procurement to the maximum extent practical and evaluates every supplier’s products and services on the basis of technical excellence, quality, reliability, service, price, delivery, and other relevant

objective factors. Enerplus prohibits Employees from making purchasing decisions on the basis of personal relationships, friendships, or the opportunity for personal financial gain.

Employees must respect the terms of supplier and contractor contracts and licensing agreements and safeguard all confidential information received from a contractor or supplier, including pricing, technology, or proprietary design information. This confidential information must not be disclosed to anyone outside Enerplus without the written permission of the supplier or contractor.

All contractors who exchange or receive personal information from Enerplus must have privacy policies and practices in compliance with applicable Canadian and United States federal, provincial and state laws.

Anti-Corruption

Enerplus is committed to honesty and integrity in all of its business operations and will actively avoid corruption. We recognize that we may operate in jurisdictions which have different standards of ethical behaviour. Regardless of location, Employees shall carry out their duties in accordance with the principles set out in this Code and, specifically, will comply with all applicable anti-bribery and fair practices legislation.

Acts of corruption, either direct or indirect, are prohibited. Accordingly, Employees shall not engage in any acts that are improper or could appear to be improper, including the following:

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Paying bribes or kickbacks to, or accepting bribes or kickbacks from, public officials or private individuals;

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Making facilitation payments;

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Failing to keep complete and accurate records of transactions;

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Approving payment of invoices or expenses without proper back-up or scrutiny;

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Engaging in joint ventures or retaining agents or consultants to deal with public officials without conducting adequate due diligence of the counterparty’s previous activities or reputation.

Compliance with these principles will ensure that Enerplus’ business activities are transparent and our commercial relationships are based upon honesty and fairness.

Gifts and Entertainment

Reasonable gifts and entertainment are a part of normal business courtesy and are not prohibited. In many cultures, exchanging gifts or entertainment is designed to foster trust in a business relationship. However, Employees should always use good judgment and discretion to avoid the appearance of impropriety or obligation. Enerplus Employees should be certain that any gifts given or received, or entertainment hosted or attended as a guest, do not violate the law, customary business practices, or this Code of Business Conduct.

While Employees may exchange or accept gifts with their counterparties and suppliers as part of normal business courtesy, no gift, favour, or payment should be accepted which imparts a future obligation on the Employee or was given in an attempt to influence decisions regarding the business of Enerplus. Additionally, the value of the gifts exchanged should be reasonable, and the exchanges should occur infrequently.

Likewise, while Employees may be participants in entertainment with their counterparties and suppliers as hosts or guests in the normal course of a business relationship, Employees must not be participants when the entertainment is an attempt to influence decisions regarding the business of Enerplus or imparts a future obligation on the Employee. Additionally, the value of the entertainment should be reasonable and the Employee’s participation should occur infrequently. Finally, Employees are prohibited from participating in inappropriate entertainment as either a guest or a host.

Gifts and entertainment in excess of $300 may be accepted, if approved in advance by an executive officer. Executive officers may accept such gifts and entertainment with prior approval from their leader or the chairman of the board of directors. If a gift has been received but, given the circumstances, the gift is determined to be inappropriate, your

manager may require the gift to be returned to the originator. An Employee who has any doubt about the propriety of a gift or entertainment should contact his/her supervisor or the People & Culture Department before accepting the gift or participating in the proposed activity.

Obtaining and Using Competitor Information

While information about our competitors, counterparties, and suppliers is a valuable asset, the law and our standards of appropriate business conduct require that our Employees obtain this information legally. It is not unusual to obtain information about other organizations, including our competitors, through legal and ethical means such as public documents, public presentations, journal and magazine articles, and other published and spoken information. However, Employees are prohibited from obtaining proprietary or confidential information about our competitors, counterparties, or suppliers through illegal means, or from using any proprietary or confidential information acquired during a prior employment relationship. It is also not acceptable to use or seek to acquire proprietary or confidential information when doing so would require anyone to violate a contractual arrangement, such as a confidentiality agreement with a prior employer. Employees are prohibited from taking any improper actions to gain information about our competitors, counterparties, and suppliers.

Our Communities

Environmental Compliance

Enerplus is dedicated to complying with all relevant environmental laws and regulations and requires Employees to comply with these laws and regulations as well. It is the duty of each Employee to report what he/she believes to be environmental violations to his/her supervisor or the Corporate Sustainability Department. For further information, please refer to the Environmental, Social and Governance (ESG) Policy.

Political Contributions

Only Enerplus’ President and CEO may authorize use of the Corporation’s resources to support political activities. Employees must not use Enerplus’ money, credit, property, or services for political activities. Outside of Enerplus business hours, Employees may participate in any political activities of their choice, but Enerplus will not support or reimburse Employees financially.

Requests for Information from the Media and Public

Enerplus’ President and CEO, Senior Vice-Presidents, Vice-Presidents of Operations and the Investor Relations Department are authorized to work with the media directly, and may designate other Employees to serve as spokespersons for the Corporation in specific circumstances (e.g., emergency management). When Enerplus provides information to the news media, Enerplus has the obligation to report accurately and completely all related material facts. In order to ensure that Enerplus complies with its obligations, Employees who are contacted by the media for information regarding Enerplus’ business activities and plans, financial information, or Enerplus’ position on public issues, must refer the request to the Investor Relations Department. Likewise, all requests from the media for interviews must be directed to Investor Relations. Employees may not answer any questions from any member of the media unless they have participated in Enerplus’ media training program and been designated as spokespersons.

Press Releases

Press releases allow Enerplus to announce important and relevant information to the public through the media. If a business unit or department within Enerplus anticipates the necessity for a press release to be created, the business unit or department must contact the Investor Relations Department to discuss the appropriateness of such a release and to provide the needed information. All press releases must be issued by the Investor Relations Department.

Public Speaking and Publishing Articles

Speeches and articles offer excellent opportunities for Enerplus and its Employees to present topics, ideas, and information of interest to business and professional audiences. These communications provide the public with a clearer understanding of Enerplus and its various business units. A speech or article on a professional topic written by an Employee

for delivery to an audience or publication represents Enerplus. Speeches and articles must be approved by the Investor Relations Department prior to the speaking engagement or submission for publication. The Communications group may assist as well.

Social Networking and Blogs

Employees have the right to create personal blogs and postings on social networking websites. However, online misconduct can be grounds for discipline, even if it does not occur during business hours or using Enerplus’ resources. Inappropriate content for online employee postings includes, but is not limited to, the following:

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Enerplus’ confidential or proprietary information;

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Information concerning Enerplus or Employees that would violate this Code or any other Enerplus policies, including the Privacy Policy; and

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Negative comments about Enerplus or Employees, or that would harm the reputation of Enerplus or its Employees.

Employees should consult the Social Media Guidelines posted on the intranet for further information.

Community Involvement

Enerplus directly and through its Employees contributes to the general well-being and improvement of towns, cities, and regions where it has operations. Enerplus provides support to worthwhile community programs in areas such as social welfare, health, education, and arts and culture to promote the development of positive relationships in the areas where we have business interests. Enerplus also encourages the recruitment of qualified local personnel where practical. All Enerplus community involvement activities and requests for corporate contributions must be approved by the Communications group in coordination with the Stakeholder Engagement team.

While Enerplus encourages Employees to participate in charitable organizations and other community activities of their choice, these outside activities should not interfere with job duties. Accordingly, prior approval from your manager must be obtained when participation is supported by Enerplus and when utilizing Enerplus resources (including work time, e.g. days of caring). Where participation is on personal time and does not conflict with job duties then approval is not required. No Employee may pressure another Employee to express a view that is contrary to a personal belief or to contribute to or support political, religious, or charitable causes.

Community Projects

When a new project or business issue affects a local community, the business unit should seek the guidance of the Stakeholder Engagement team and the Communications group to help facilitate communications with the affected community. These groups will serve as support, proactively building and maintaining relationships with local communities as project development occurs. This will include developing a consistent platform to help educate landowners and communities on Enerplus’ operations and safety programs.

Reporting Violations and Resources for Guidance

This Code and other Enerplus policies provide general information for seeking guidance or reporting violations of the Code to supervisors, department heads, the People & Culture Department or our General Counsel. For more serious breaches of this Code, or if you have not received a satisfactory response, please refer to the Whistleblower Policy discussed below.

Whistleblower Policy

Enerplus has instituted a Whistleblower Policy to provide for the reporting and review of concerns relating to accounting and auditing matters, as well as other corporate misconduct and breaches of this Code of Business Conduct. Like the Code of Business Conduct, the Whistleblower Policy is designed to encourage ethical behaviour by all Enerplus Employees. Further details, and procedures for submitting a report, are set out in the Whistleblower Policy.

Disciplinary Action

This Code is intended to help Employees conduct themselves in a manner consistent with our values. Employees may face disciplinary action if they:

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Violate this Code

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Encourage or help other Employees to violate this Code

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Condone other Employees who violate this Code

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Fail to report a Code violation

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Conceal a Code violation

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Retaliate against any Employee who reports a Code violation in good faith

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Fail as an officer, director, manager, or supervisor to take appropriate steps to ensure compliance with this Code

Disciplinary action may include one or more of the following:

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A warning

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A written reprimand

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Mandatory reimbursement of losses or damages

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Suspension

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Demotion

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Termination of employment with Enerplus

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Referral for criminal prosecution or civil action

Management has the discretion to determine the level and type of discipline that is appropriate in any given circumstance.

Clawback Policy

In addition to other possible disciplinary action, in cases of fraud or other intentional illegal conduct which affects Enerplus and its business, Employees may be subject to a clawback of their incentive compensation related to such activity. For further information, please refer to the Clawback Policy.

Monitoring

Enerplus will monitor compliance with its policies and procedures, including this Code.

Questions/Effect of this Code of Business Conduct

This Code is not a comprehensive listing of every Enerplus policy or applicable law. If questions arise about what this Code means or how it should be applied, Employees should contact their supervisor, department head or the People & Culture Department.

Sources of Information



Manager, People & Culture	(403) 298-2277
Manager, Corporate Sustainability	(403) 298-8940
VP, General Counsel & Corporate Secretary	(403) 298-4413

EXHIBIT 99.12

Supplemental Information About Crude Oil and Natural Gas Producing Activities (unaudited)

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 ASC Topic 932 "Extractive Activities – Oil and Gas” (“ASC 932”). All amounts pertaining to Enerplus’ audited consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). 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 January 25, 2021, Enerplus entered into an agreement (the “Purchase Agreement”) to acquire the equity interests of Bruin E&P HoldCo, LLC (“Bruin”), a pure play Williston Basin private company, for total cash consideration of US$465 million, subject to certain adjustments (the “Bruin Acquisition”). Closing of the Bruin Acquisition is expected to occur early in March 2021 and is subject to customary closing conditions. The information presented in this document does not give effect to the Bruin Acquisition. For information on the Bruin Acquisition and Bruin’s reserve data and certain other crude oil and gas information as at December 31, 2020 refer to the material change report dated January 29, 2021 in connection with the Bruin Acquisition and available under the Enerplus’ SEDAR profile at www.sedar.com and on the Enerplus’ EDGAR profile under Form 6-K at www.sec.gov.

A. ESTIMATED PROVED CRUDE OIL AND NATURAL GAS RESERVE QUANTITIES

Users of this information should be aware that the process of estimating quantities of "proved" crude oil, natural gas and natural gas liquids reserves is very complex, requiring significant subjective decisions in the evaluation of 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 Enerplus’ reserves to be materially different from that presented.

ASC 932 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 (the “Constant Price”). Proved reserves and production volumes are presented net of royalties in accordance with U.S. practice.

Proved reserves, proved developed reserves and proved undeveloped reserves are defined under ASC 932. Proved crude oil and gas reserves are those quantities of crude 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 Enerplus does not believe differences are material to Enerplus’ proved reserves. The reserves data presented in this Exhibit are a summary of evaluations, and as a result the tables may contain slightly different quantities than the evaluations themselves due to rounding. Additionally, the columns and rows in the tables may not add due to rounding. See "Presentation of Enerplus' Crude Oil and Gas Reserves, Contingent Resources, and Production Information" in Enerplus' Annual Information Form.

Subsequent to December 31, 2020, 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’ proved crude oil, natural gas and natural gas liquids (NGLs) reserves are located in the United States, primarily in the states of Colorado, Montana, North Dakota, and Pennsylvania, as well as western Canada, primarily in Alberta and Saskatchewan. Enerplus’ net proved reserves summarized in the following table represent Enerplus’ lessor royalty, overriding royalty, and working interest share of reserves, after deduction of any Crown, freehold and overriding royalties as of December 31, 2020.


	Canada		United States		Total		Total
	Crude Oil	Natural	Crude Oil	Natural	Crude Oil	Natural	All
	and NGLs	Gas	and NGLs	Gas	and NGLs	Gas	Products
	(Mbbls)	(MMcf)	(Mbbls)	(MMcf)	(Mbbls)	(MMcf)	(Mboe)
Reserves at December 31, 2017	27,383	36,551	74,270	472,459	101,653	509,010	186,488
Purchases of reserves in place	—	—	128	73	128	73	140
Sales of reserves in place	(40)	(4,252)	(136)	(64)	(176)	(4,316)	(895)
Discoveries and extensions	965	1,180	24,791	64,451	25,756	65,631	36,695
Revisions of previous estimates	269	930	4,020	189,251	4,289	190,182	35,986
Improved recovery	541	17	—	—	541	17	544
Production	(2,988)	(9,083)	(11,577)	(67,901)	(14,565)	(76,984)	(27,396)
Proved Developed and Undeveloped
Reserves at December 31, 2018	26,130	25,343	91,496	658,270	117,626	683,613	231,562
Purchases of reserves in place	—	—	—	—	—	—	—
Sales of reserves in place	(814)	(190)	—	—	(814)	(190)	(845)
Discoveries and extensions	375	936	22,689	191,506	23,064	192,442	55,138
Revisions of previous estimates	695	(450)	(8,193)	(55,505)	(7,498)	(55,956)	(16,823)
Improved recovery	—	—	—	—	—	—	—
Production	(2,707)	(7,882)	(13,216)	(74,455)	(15,923)	(82,337)	(29,646)
Proved Developed and Undeveloped
Reserves at December 31, 2019	23,680	17,756	92,777	719,816	116,456	737,572	239,385
Purchases of reserves in place	—	—	—	—	—	—	—
Sales of reserves in place	—	—	—	—	—	—	—
Discoveries and extensions	—	—	1,931	16,613	1,931	16,613	4,700
Revisions of previous estimates	(5,115)	943	(39,543)	(263,700)	(44,658)	(262,757)	(88,451)
Improved recovery	—	—	—	—	—	—	—
Production	(2,382)	(4,239)	(12,690)	(65,672)	(15,072)	(69,911)	(26,724)
Proved Developed and Undeveloped
Reserves at December 31, 2020	16,182	14,461	42,475	407,056	58,657	421,517	128,910
Proved Developed Reserves
December 31, 2017	24,883	35,347	39,655	416,313	64,537	451,660	139,814
December 31, 2018	23,065	25,271	50,645	458,649	73,710	483,920	154,363
December 31, 2019	20,480	17,684	49,852	475,155	70,332	492,839	152,472
December 31, 2020	15,421	14,447	37,966	360,446	53,387	374,893	115,869
Proved Undeveloped Reserves
December 31, 2017	2,501	1,204	34,615	56,146	37,116	57,350	46,674
December 31, 2018	3,065	72	40,852	199,621	43,916	199,693	77,198
December 31, 2019	3,200	73	42,925	244,661	46,124	244,733	86,913
December 31, 2020	761	13	4,508	46,610	5,270	46,624	13,040

Purchases of reserves in place

In 2018, the Company acquired minor working interest reserve volumes through a land swap in the Bakken/Three Forks crude oil property in North Dakota. As part of this land swap, the Company also divested an almost equal amount of working interest reserve volumes within the Bakken/Three Forks crude oil property.

In 2019, the Company acquired no additional working interest reserve volumes through purchases.

In 2020, the Company acquired no additional working interest reserve volumes through purchases.

Sales of reserves in place

In 2018, the company sold working interests in developed and undeveloped land in one crude oil property and eight natural gas properties located in Alberta.

In 2018, the Company also divested minor working interest reserve volumes through a land swap in the Bakken/Three Forks crude oil property in North Dakota. As part of this land swap, the Company also acquired an almost equal amount of working interest reserve volumes within the Bakken/Three Forks crude oil property.

In 2019, the company sold working interests in developed and undeveloped land in three crude oil properties located in Saskatchewan and 11 natural gas properties located in Alberta.

In 2020, the Company did not sell working interests of any of its reserves in place.

Discoveries and extensions

The Company added 24,791 Mbbl, 22,026 Mbbl and 1,655 Mbbl of net proved crude oil and NGLs reserves on its Bakken/Three Forks properties in 2018, 2019 and 2020, respectively. The Company added 52,880 MMcf, 179,834 MMcf and 15,299 MMcf of net proved natural gas reserves in 2018, 2019 and 2020, respectively, on its Marcellus natural gas property. These discoveries and extensions were all primarily due to successful well development.

In 2018, Canadian discoveries and extensions accounted for an increase of 965 Mbbl of net proved crude oil and NGLs reserves and 1,180 MMcf of net proved natural gas reserves in the Med Hat Glauconitic C polymer flood and Giltedge crude oil properties located in Alberta, and the Saskatchewan Freda Lake crude oil property.

In 2019, Canadian discoveries and extensions accounted for an increase of 282 Mbbl of net proved crude oil reserves in the Saskatchewan Freda Lake crude oil property, and 59 Mbbl of net proved crude oil reserves and 936 MMcf of net proved natural gas reserves in the Ferrier, Fir and Willesden Green North properties located in Alberta.

In 2020, there were no discoveries or extensions in Canadian crude oil or natural gas properties.

Revisions of previous estimates

In 2018, positive revisions to United States crude oil reserves were primarily due to an increase in the Constant crude oil price compared to 2017. Positive revisions to United States natural gas reserves were primarily due to improved production performance and also an increase in the Constant gas price forecast compared to 2017.

In 2019, negative revisions to United States crude oil reserves were primarily due to a decrease in the Constant crude oil price forecast, as well as economic truncation due to an increase in operating expenses. Negative revisions to United States natural gas were primarily due to revised development plans and deletion of proved undeveloped wells in the Marcellus natural gas property.

In 2020, negative revisions to United States crude oil reserves were primarily due to a decrease in the Constant crude oil price forecast, which caused economic truncation of producing volumes and the removal of undeveloped locations that were no longer economic. Negative revisions to United States natural gas were also primarily due to a decrease in the Constant gas price forecast, which caused economic truncations of producing volumes and the removal of no longer economic undeveloped locations.

In 2018, the positive revisions to Canadian crude oil reserves were primarily due to an increase in the Constant crude oil price forecast compared to 2017. Positive revisions to Canadian natural gas reserves were primarily due to improved production performance.

In 2019, positive revisions to Canadian crude oil reserves were primarily due to improved production performance. Negative revisions to Canadian natural gas reserves were primarily due to a decrease in the Constant gas price forecast compared to 2018.

In 2020, negative revisions to Canadian crude oil reserves were due to negative revisions to previous estimates in the Medicine Hat Glauconitic C polymer flood and a decrease in the Constant crude oil price forecast compared to 2019. Conversely, an increase in the Constant price forecast for Canadian gas compared to 2019 resulted in positive revisions to Canadian natural gas reserves.

Improved Recovery

In 2018 in the Ante Creek North waterflood property located in Alberta, there was an improved recovery revision of 541 Mbbl of net proved crude oil and NGLs reserves and 17 MMcf of net proved natural gas reserves.

B. CAPITALIZED COSTS RELATED TO CRUDE OIL AND GAS PRODUCING ACTIVITIES

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


	2020		2019		2018

	(in $ thousands)
Capitalized costs⁽¹⁾	$	15,227,076	$	15,088,724	$	14,773,082
Less accumulated depletion, depreciation and impairment		(14,651,517)		(13,541,362)		(13,479,141)
Net capitalized costs	$	575,559	$	1,547,362	$	1,293,941

Note:

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

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

Costs incurred in connection with crude oil and gas acquisition, exploration and development activities are presented in the table below. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire crude oil and gas properties, including an allocation of purchase price on business combinations that result in property acquisitions. Development costs include asset retirement costs capitalized and the costs of drilling and equipping development wells and facilities to extract, gather and store crude 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.


	For the Year Ended December 31, 2020
	Canada		United States		Total

	(in $ thousands)
Acquisition of properties:
Proved	$	303	$	—	$	303
Unproved		2,340		7,478		9,818
Exploration costs		132		645		777
Development costs		25,527		269,789		295,316
	$	28,302	$	277,912	$	306,214


	For the Year Ended December 31, 2019
	Canada		United States		Total

	(in $ thousands)
Acquisition of properties:
Proved	$	2,765	$	1,230	$	3,995
Unproved		3,244		17,167		20,411
Exploration costs		359		616		975
Development costs		56,729		587,800		644,529
	$	63,097	$	606,813	$	669,910


	For the Year Ended December 31, 2018
	Canada		United States		Total

	(in $ thousands)
Acquisition of properties:
Proved	$	—	$	6,055	$	6,055
Unproved		3,888		15,624		19,512
Exploration costs		641		979		1,620
Development costs		61,632		547,667		609,299
	$	66,161	$	570,325	$	636,486

D. RESULTS OF OPERATIONS FOR CRUDE OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to Enerplus' crude oil and gas producing activities for the years ended December 31, 2020, 2019 and 2018:


	For the Year Ended December 31, 2020
	Canada		United States		Total

	(in $ thousands)
Revenue
Sales⁽¹⁾	$	96,499	$	640,706	$	737,205
Deduct⁽²⁾
Production costs⁽³⁾		65,650		380,211		445,861
Depletion, depreciation and accretion (“DD&A”)		46,783		246,373		293,156
Impairment		134,349		1,063,194		1,197,543
Current and deferred income tax provision (recovery)		(24,584)		(236,170)		(260,754)
Results of operations for crude oil and gas producing activities	$	(125,699)	$	(812,902)	$	(938,601)
DD&A per net BOE unit of production	$	15.15		10.42		10.97


	For the Year Ended December 31, 2019
	Canada		United States		Total

	(in $ thousands)
Revenue
Sales⁽¹⁾
Deduct⁽²⁾	$	177,299	$	1,077,507	$	1,254,806
Production costs⁽³⁾
Depletion, depreciation and accretion (“DD&A”)		84,781		433,997		518,778
Impairment		59,936		296,894		356,830
Current and deferred income tax provision (recovery)		451,121		—		451,121
Results of operations for crude oil and gas producing activities		(2,887)		50,748		47,861
DD&A per net BOE unit of production	$	(415,652)	$	295,868	$	(119,784)
	$	14.91	$	11.59	$	12.04


	For the Year Ended December 31, 2018
	Canada		United States		Total

	(in $ thousands)
Revenue
Sales⁽¹⁾	$	198,263	$	1,094,473	$	1,292,736
Deduct⁽²⁾
Production costs⁽³⁾		89,584		359,426		449,010
Depletion, depreciation and accretion (“DD&A”)		58,333		245,941		304,274
Current and deferred income tax provision (recovery)		3,515		99,696		103,211
Results of operations for crude oil and gas producing activities	$	46,831	$	389,410	$	436,241
DD&A per net BOE unit of production	$	12.96	$	10.74	$	11.11

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 crude 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 CRUDE 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, 2020
	Canada		United States		Total

	(in $ millions)
Future cash inflows	$	573		1,849		2,422
Future production costs		345		1,118		1,463
Future development and asset retirement costs		267		233		501
Future income tax expenses		—		—		—
Future net cash flows	$	(39)		497		458
Deduction: 10% annual discount factor		(92)		56		(37)
Standardized measure of discounted future net cash flows	$	53		442		495



	As at December 31, 2019
	Canada		United States		Total

	(in $ millions)
Future cash inflows	$	1,283		6,395		7,678
Future production costs		591		2,210		2,801
Future development and asset retirement costs		321		1,365		1,685
Future income tax expenses		—		254		254
Future net cash flows	$	371		2,566		2,937
Deduction: 10% annual discount factor		76		893		968
Standardized measure of discounted future net cash flows	$	296		1,673		1,969



	As at December 31, 2018
	Canada		United States		Total

	(in $ millions)
Future cash inflows	$	1,350		7,090		8,440
Future production costs		643		2,109		2,752
Future development and asset retirement costs		143		1,316		1,459
Future income tax expenses		—		508		508
Future net cash flows	$	564	$	3,157	$	3,721
Deduction: 10% annual discount factor		206		1,177		1,383
Standardized measure of discounted future net cash flows	$	358	$	1,980	$	2,338

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



	2020		2019		2018

	(in $ millions)
Beginning of year	$	1,969	$	2,338	$	1,540
Sales of crude oil and natural gas produced, net of production costs		(291)		(736)		(844)
Net changes in sales prices and production costs		(2,707)		(996)		1,195
Changes in previously estimated development costs incurred during the period		291		618		594
Changes in estimated future development costs		739		(506)		(892)
Extension, discoveries and improved recovery, net of related costs		40		889		978
Purchase of reserves in place		—		—		2
Sales of reserves in place		—		(7)		(2)
Net change resulting from revisions in previous quantity estimates		148		(97)		(114)
Accretion of discount		182		232		143
Net change in income taxes		110		145		(247)
Other significant factors (Exchange rate)		14		89		(15)
End of year	$	495	$	1,969	$	2,338