40-F

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, 2022	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

and

US Bank Tower, Suite 2200, 950 - 17th Street

Denver, Colorado, United States of America 80202-2805

(720) 279-5500

(Address and telephone number of Registrant’s principal executive offices)
Enerplus Resources (USA) Inc

US Bank Tower, Suite 2200, 950 - 17th Street

Denver, Colorado, United States of America 80202-2805

(720) 279-5500

(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.
217,285,537 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.
☐ Auditor Name: KPMG LLP Auditor Location: Calgary, Canada Auditor Firm ID: 85

† 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. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant

included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based

compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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. 333-257151) 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, 2022, 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, 2022, 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, 2022 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, 2022, 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, 2022 is attached as Exhibit 99.3 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, 2022, 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, 2022, 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. Jeffrey W. Sheets, a member and the chair of the Registrant’s Audit & Risk Management Committee, and Ms. Sherri A. Brillon, a member of the Registrant’s Audit

& Risk Management Committee, are each an “audit committee financial expert” (as such term is defined by the rules and regulations of the Securities and Exchange Commission) and are each “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 Code of Business Conduct & Ethics (the “Code”) is available for viewing on the Registrant’s website at www.enerplus.com. Any amendments to the Code or waivers granted from any provision of the Code from time to time will be posted to the Registrant’s website within five business days of the amendment or waiver and will remain available for a twelve-month period. Information on or connected to our website, even if referred to herein, does not constitute part of this annual report on Form 40-F.

Since the adoption of the Code, there have not been any waivers, including implicit waivers, granted from any provision of the Code. The Registrant amended the Code effective February 1, 2023. There were no amendments made to the Code of Business Conduct of a substantive nature.

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

The required disclosure is included under the heading “Appendix E – Audit & Risk Management Committee Disclosure Pursuant to National Instrument 52-110 – External Auditor Service Fees” in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2022 attached as Exhibit 99.1 to this Annual Report on Form 40-F.

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 concluded 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 does not have any commitments or obligations, including contingent obligations, arising from arrangements with unconsolidated entities or persons (which are not otherwise discussed in the Registrant's Management’s Discussion and Analysis for the year ended December 31, 2022 attached as Exhibit 99.3 to this Annual Report on Form 40-F) that have or are reasonably likely to have a material current or future effect on a registrant’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, cash requirements, or capital resources.

CONTRACTUAL OBLIGATIONS

Disclosure regarding the Registrant’s contractual obligations is provided under the heading “Liquidity and Capital Resources – Commitments and Contingencies” in the Registrant’s Management’s Discussion and Analysis for the year ended December 31, 2022 attached as Exhibit 99.3 to this Annual Report on Form 40-F, which disclosure is incorporated by reference herein, and in Note 17 to the Registrant’s audited annual consolidated financial statements for the year ended December 31, 2022 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 Jeffrey W. Sheets (Committee Chair), Judith D. Buie, Sherri A. Brillon, Mark A. Houser and Sheldon B. Steeves. 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 23, 2023

EXHIBIT INDEX

99.1	Annual Information Form for the year ended December 31, 2022 dated February 23, 2023.
99.2	Audited annual consolidated financial statements for the year ended December 31, 2022.
99.3	Management’s Discussion and Analysis for the year ended December 31, 2022.
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.
101	Interactive Data File.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

EX-99.1

Exhibit 99.1

ANNUAL INFORMATION FORM

For the year ended December 31, 2022

February 23, 2023

TABLE OF CONTENTS Page

GLOSSARY OF TERMS	1
ABBREVIATIONS, CONVERSIONS AND CURRENCY	3
PRESENTATION OF OIL AND GAS RESERVES, CONTINGENT RESOURCES, AND PRODUCTION INFORMATION	4
Note To Reader Regarding Oil And Gas Information, Definitions And National Instrument 51-101	4
Disclosure Of Reserves And Production Information	4
Barrels Of Oil And Cubic Feet Of Gas Equivalent	5
Interests In Reserves, Contingent Resources, Production, Wells And Properties	5
Reserves Categories And Levels Of Certainty For Reported Reserves	6
Development And Production Status	6
Description Of Price And Cost Assumptions	6
PRESENTATION OF FINANCIAL INFORMATION	7
FORWARD-LOOKING STATEMENTS AND INFORMATION	7
CORPORATE STRUCTURE	10
Enerplus Corporation	10
Material Subsidiaries	10
Organizational Structure	10
GENERAL DEVELOPMENT OF THE BUSINESS	11
Developments In The Past Three Years	11
BUSINESS OF THE CORPORATION	12
Overview	12
Summary Of Principal Production Locations	13
Capital Expenditures And Costs Incurred	14
Exploration And Development Activities	14
Oil And Natural Gas Wells And Unproved Properties	14
Description Of Properties	15
Quarterly Production History	17
Quarterly Netback History	18
Tax Horizon	20
Marketing Arrangements And Forward Contracts	21
OIL AND NATURAL GAS RESERVES	22
Summary Of Reserves	22
Forecast Prices And Costs	23
Undiscounted Future Net Revenue By Reserves Category	24
Net Present Value Of Future Net Revenue By Reserves Category And Product Type	24
Estimated Production For Gross Reserves Estimates	24
Future Development Costs	26
Reconciliation Of Reserves	26
Undeveloped Reserves	29
Significant Factors Or Uncertainties	30
Proved And Probable Reserves Not On Production	31
SUPPLEMENTAL OPERATIONAL INFORMATION	32
Environmental, Social And Governance	32
Insurance	34
Personnel	35
DESCRIPTION OF CAPITAL STRUCTURE	36
Common Shares	36
Preferred Shares	36
Senior Unsecured Notes	36
SLL Credit Facilities	36
DIVIDENDS	37
Dividend Policy And History	37
Stock Dividend Program	37
INDUSTRY CONDITIONS	38
Overview	38
Pricing And Marketing Of Crude Oil And Natural Gas	38
Royalties And Incentives	39
Land Tenure	40
Environmental Regulation	40
Worker Safety	43
RISK FACTORS	45
MARKET FOR SECURITIES	63
DIRECTORS AND OFFICERS	64
Directors Of The Corporation	64

i

Officers Of The Corporation	65
Common Share Ownership	65
Conflicts Of Interest	66
Audit & Risk Management Committee Disclosure	66
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	66
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	66
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS	66
INTERESTS OF EXPERTS	67
TRANSFER AGENT AND REGISTRAR	67
ADDITIONAL INFORMATION	67
APPENDIX A – CONTINGENT RESOURCES INFORMATION	A-1
APPENDIX B – SUPPLEMENTAL INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES (U.S. RULES)	B-1
APPENDIX C – REPORT ON RESERVES DATA AND CONTINGENT RESOURCES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	C-1
APPENDIX D – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	D-1
APPENDIX E – AUDIT & RISK MANAGEMENT COMMITTEE DISCLOSURE PURSUANT TO NATIONAL INSTRUMENT 52-110	E-1

ii

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 23, 2023, for the year ended December 31, 2022 and all appendices hereto.

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

"Board" means the board of directors of the Corporation

"Bruin Acquisition" means the acquisition by Enerplus USA of all of the equity interests of Bruin E&P HoldCo, LLC, a Delaware limited liability company, completed on March 10, 2021. See "General Development of the Business – Developments in the Past Three Years"

"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

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

"Corporation" means Enerplus Corporation, a corporation existing under the ABCA, and, where the context requires, its subsidiaries, taken as a whole

"Credit Facilities" means, collectively, the SLL Credit Facilities 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

"Dunn County Acquisition" means the acquisition by Enerplus USA of certain assets in the Willison Basin from Hess Bakken Investments II, LLC, completed on April 30, 2021. See "General Development of the Business – Developments in the Past Three Years"

"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"

"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, 2022 and 2021 and for each of the years in the three-year period ended December 31, 2022

"GHG" means greenhouse gas

"GLJ" means GLJ Ltd., independent petroleum consultants

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

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

ENERPLUS 2022 ANNUAL INFORMATION FORM    1

"McDaniel Reports" means, collectively, the independent engineering evaluations of certain of the Corporation's crude oil, natural gas liquids and natural gas reserves in North Dakota and Colorado, and the Corporation’s contingent resources associated with its North Dakota properties, prepared by McDaniel effective December 31, 2022 utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2023

"MD&A" means management's discussion and analysis for the year ended December 31, 2022

"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, 2022, utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2023

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

"NYSE" means the New York Stock Exchange

"Scope 1 Emissions" means all direct GHG emissions

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

"SEC" means the United States Securities and Exchange Commission

"Senior Unsecured Notes" means, as at December 31, 2022, the US$203.2 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"

"SLL Credit Facilities" means, collectively and as at December 31, 2022, the Corporation's US$900 million senior, unsecured, covenant-based sustainability-linked revolving credit facility and the Corporation’s US$365 million senior, unsecured, covenant-based sustainability-linked revolving credit facility, each held with a syndicate of financial institutions. See "Description of Capital Structure – SLL Credit Facilities" and "Material Contracts and Documents Affecting the Rights of Securityholders"

"Sproule" means Sproule Associates Limited, independent petroleum consultants

"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, covenant-based term credit facility with a syndicate of financial institutions initially set to mature on March 10, 2024, which was most recently converted into the US$365 million SLL Credit Facility. See "Description of Capital Structure – SLL Credit Facilities" and "Material Contracts and Documents Affecting the Rights of Securityholders"

"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

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

2    ENERPLUS 2022 ANNUAL INFORMATION FORM

Abbreviations, Conversions and Currency

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
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
MMBOE(1)	one million barrels of oil equivalent
MMbtu	one million British Thermal Units
MMcf	one million cubic feet
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. For further information, see "Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Barrels of Oil Equivalent".

In this Annual Information Form, unless otherwise indicated, all dollar amounts are in U.S. dollars and all references to "$" and "US$" are to U.S. dollars. References to "CDN$" are to Canadian dollars. On December 30, 2022, the exchange rate for one Canadian dollar, expressed in U.S. dollars and based upon the closing rate from Bloomberg, was $0.74. The average exchange rate in 2022 for one Canadian dollar, expressed in U.S. dollars and based upon the average closing rate from Bloomberg, was $0.77.

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

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

ENERPLUS 2022 ANNUAL INFORMATION FORM    3

Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information

DISCLOSURE OF RESERVES AND PRODUCTION INFORMATION

Except for the information presented in Appendix B and as otherwise noted below, all oil and gas information presented in this Annual Information Form has been prepared and is presented in accordance with the Canadian disclosure standards set forth in NI 51-101 (the “Canadian Standards").

The oil and gas reserves information of the Corporation contained in Appendix B, effective as at December 31, 2022, is prepared and presented in accordance with the provisions of the Financial Accounting Standards Board’s ASC Topic 932 Extractive Activities – Oil and Gas (“ASC 932”), which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the SEC (together with the ASC 932, the “U.S. Rules"), but does not necessarily include all of the disclosure required by the SEC disclosure requirements set forth in Subpart 1200 of Regulation S-K (the “U.S. Standards"). Concurrently with the evaluation of the Corporation’s reserves under Canadian Standards, McDaniel and NSAI prepared and reviewed estimates of the Corporation’s reserves under the U.S. Standards. The practice of preparing production and reserves data under NI 51-101 differs from the U.S. Rules. The significant differences between the two reporting requirements are described under "Notice to U.S. Readers", below.

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 Canadian Standards. Readers should also refer to the Report on Reserves Data and Contingent Resources Data by McDaniel and NSAI attached as Appendix C and the Report of Management and Directors on Oil and Gas Disclosure attached hereto as Appendix D. The effective date for the Statement of Reserves Data and Contingent Resources and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2022 and the preparation dates for such information are February 2, 2023 for the McDaniel Reports and February 7, 2023 for the NSAI Report.

For information regarding contingent resources of the Corporation and its presentation in accordance with Canadian Standards, see Appendix A.

In this Annual Information Form, all oil and natural gas production volumes are presented on a "net" basis, as described under " - Interests in Reserves, Contingent Resources, Production, Wells and Properties" below, unless expressly indicated that it is being presented on a "gross" basis in accordance with Canadian Standards.

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" and Appendix B, as applicable, for additional information.

NOTICE TO U.S. READERS

Except for the information set forth in Appendix B, all data on oil and natural gas reserves contained in this Annual Information Form has generally been prepared and is presented in accordance with Canadian Standards, which are not comparable in all respects to U.S. Standards or other foreign disclosure standards. The primary differences between the two reporting frameworks include:

● Under NI 51-101 and Canadian industry practice, reserves and production are reported using gross volumes, while the U.S. Standards and U.S. industry practice is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments, plus royalty interests. As discussed above, certain oil and gas production volumes in this Annual Information Form are presented on a net basis.

● Under NI 51-101, the Corporation has determined and disclosed estimated future net revenue from its reserves using forecast prices and escalating costs, whereas the U.S. Standards require 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.

● NI 51-101 requires that reserves and other data be reported on a more granular product type bases than required under the U.S. Standards.

4    ENERPLUS 2022 ANNUAL INFORMATION FORM

● NI 51-101 requires that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves.

● 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.

As a consequence of the foregoing, except for the reserves information set forth in Appendix B, which has been prepared in accordance with U.S. Rules, the Corporation's reserves estimates and certain production volumes that are presented on a gross basis may not be comparable to those made by companies utilizing U.S. Standards. 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.

For certain oil and gas information prepared and presented in accordance with the U.S. Rules, see Appendix B.

BARRELS OF OIL 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. The conventions BOEs, MBOEs and MMBOEs 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

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.

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.

ENERPLUS 2022 ANNUAL INFORMATION FORM    5

RESERVES CATEGORIES AND LEVELS OF CERTAINTY FOR REPORTED RESERVES

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

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

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

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

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

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

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

DEVELOPMENT AND PRODUCTION STATUS

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

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

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

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

"undeveloped reserves" are those reserves 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)

6    ENERPLUS 2022 ANNUAL INFORMATION FORM

Presentation of Financial Information

The Corporation presents its financial information in accordance with U.S. GAAP and in U.S. dollars as its reporting currency.

This Annual Information Form references certain financial measures, including "adjusted funds flow", “capital spending” and “free cash flow”, which are specified financial measures under National Instrument 52-112. See "Non-GAAP and Other Financial Measures" in the MD&A for additional detail regarding such measures, which section is incorporated by reference in this Annual Information Form.

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, 2022. 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 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:

● 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 spending programs, drilling programs, development plans and other future expenditures, including the planned allocation of capital spending 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

ENERPLUS 2022 ANNUAL INFORMATION FORM    7

●the Corporation’s ESG strategy, including specific targets relating to GHG emissions and freshwater use reductions, as well as climate change-related initiatives

● 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: stability, or no further deterioration, in the global economic and market environment, including related to the Ukraine and Russian conflict or from the COVID pandemic, variations thereof, and/or future pandemics,  epidemics, or other world-wide health crises; 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, pay dividends and other requirements or strategic initiatives, as needed; the Corporation's conduct and results of operations will be consistent with its expectations; the Corporation and its industry partners will have the ability to develop the Corporation's crude oil and natural gas properties in the manner currently contemplated; a lack of infrastructure, government regulations or export bans do 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.

For the purposes of the disclosure under the “Environmental, Social and Governance” sub-heading within this Annual Information Form, the term “material” is not used for, does not have, and is not intended to have, the same meaning as such term is assigned under applicable securities laws, including, but not limited to, with respect to financial materiality, materiality to investors or creditors, enterprise value, or other indications of financial impact, and is used solely to reflect the Corporation’s identification of those ESG areas that the Corporation has determined within its judgement present significant ESG risks or opportunities to its operations.

The Corporation's current 2023 capital spending budget of between $500 to $550 million contained in this Annual Information Form assumes: a WTI price of $80 per barrel, a Bakken crude oil price differential of $0.75 per barrel above WTI, a NYMEX natural gas price of $3.50 per Mcf, a Marcellus natural gas price differential of $0.75 per Mcf below NYMEX and a foreign exchange rate of CDN/USD 0.75.

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:

● 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 economic sanctions, a global pandemic or mandated production curtailments, potential export bans initiated by governments 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, including risks of recession, inflation, interest rate increases and foreign exchange fluctuations

● changes in political environments (e.g., geopolitical and technopolitical) and public opinion

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

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

● failure to realize anticipated benefits of recently completed or future acquisitions

8    ENERPLUS 2022 ANNUAL INFORMATION FORM

● 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

● the ability of the Corporation to achieve specific targets that are part of its ESG strategy, including those relating to Scope 1 and Scope 2 GHG emissions intensity, methane emissions intensity and freshwater use reductions, as well as other climate change-related initiatives

● 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

● 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, including those which are climate change-related, 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 and/or impact the Corporation's production and operations

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.

ENERPLUS 2022 ANNUAL INFORMATION FORM    9

Corporate Structure

ENERPLUS CORPORATION

The Corporation was incorporated on August 12, 2010 under the ABCA for the purposes of participating in a plan of arrangement under the ABCA, pursuant to which the business of Enerplus Resources Fund, as the Corporation's predecessor, was transitioned to the Corporation on January 1, 2011. Prior to this transaction, the business of the Corporation was carried on by Enerplus Resources 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 Corporation’s head offices are located at The Dome Tower, 3000, 333 - 7th Avenue S.W., Calgary, Alberta, T2P 2Z1, which is also its registered office, and at The US Bank Tower, 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, 2022, 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, 2022 is set forth below.

10    ENERPLUS 2022 ANNUAL INFORMATION FORM

General Development of the Business

DEVELOPMENTS IN THE PAST THREE YEARS

Developments in 2020

In early 2020, the Corporation’s focus was on maintaining a strong balance sheet and returning cash to shareholders through its monthly dividend and share repurchases. With the onset of the COVID pandemic in March of 2020, there was a sudden global economic downturn creating significant challenges for the energy industry and reduced global demand for crude 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 in North Dakota, and temporarily curtailed production from certain wells across its crude oil and natural gas liquids properties during the second quarter of 2020 to preserve cash flow. As commodity prices improved, Enerplus brought the majority of the curtailed production back online by early July 2020 and resumed limited completion activity during the fourth quarter under a lower capital spending program. The Corporation continued its monthly dividend through 2020; however, the Corporation did not renew its normal course issuer bid in order to preserve capital and maintain its balance sheet strength.

Developments in 2021

ACQUISITIONS & ASSET SALES

On March 10, 2021, the Corporation completed the Bruin Acquisition for approximately $465 million, before purchase price adjustments of $45 million, resulting in the final purchase price of approximately $420 million. The Bruin Acquisition included approximately 24,000 BOE/day of gross production (72% tight oil, 14% NGLs and 14% natural gas) at the time of closing and was financed with the Term Facility and equity financing completed on February 3, 2021.  

On April 30, 2021, the Corporation completed the Dunn County Acquisition involving certain crude oil and natural gas assets comprised of 78,700 net acres in the Williston Basin for total cash consideration of $312 million, before purchase price adjustments and transaction costs of $5.2 million, resulting in the final purchase price of $306.8 million. The Dunn County Acquisition included approximately 6,000 BOE/day of gross production (76% tight oil, 10% NGLs, and 14% natural gas) at the time of closing and was financed with cash on hand and by borrowing on the $900 million SLL Credit Facility.

On November 2, 2021, the Corporation completed the sale of its Sleeping Giant (Montana) and Russian Creek (North Dakota) interests in the Williston Basin for total cash consideration of $115 million, before purchase price adjustments and transaction costs of $7.2 million, resulting in the final purchase price of $107.8 million. Under this transaction, the Corporation was eligible to receive up to an additional $5 million contingent upon where WTI settled for each of 2022 and 2023. In January 2023, the Corporation received a $2.5 million contingent payment as WTI averaged over $65 per barrel in 2022; the second payment will be received if WTI averages over $60 per barrel in 2023. The divested assets included approximately 3,000 BOE/day of gross production (76% tight oil, 1% NGLs and 23% natural gas).

For a description of the Corporation's Bakken interests, see "Business of the Corporation – Description of Properties – Crude Oil Properties".

FINANCINGS

Equity Financing

On February 3, 2021, Enerplus completed a CDN$132 million equity offering with a total of 33,062,500 Common Shares issued. Net proceeds from the offering were used to finance the Bruin Acquisition and to fund increased capital expenditures on the acquired properties and other expenses in connection with the Bruin Acquisition.

Credit Facilities

Upon closing of the Bruin Acquisition on March 10, 2021, Enerplus entered into a three-year senior unsecured $400 million Term Facility, which was set to mature on March 10, 2024. The Term Facility loan included financial and other covenants consistent with the $900 million SLL Credit Facility. See " – Developments in 2022 – Financing" below.

On April 29, 2021 Enerplus increased and extended its senior, unsecured bank credit facility to $900 million with a maturity date of October 31, 2025. As part of the extension of the SLL Credit Facility, the Corporation transitioned the facility to a sustainability-linked credit facility.

See  "Description of Capital Structure" and "Material Contracts and Documents Affecting the Rights of Securityholders".

ENERPLUS 2022 ANNUAL INFORMATION FORM    11

SHAREHOLDER RETURNS – DIVIDEND & SHARE REPURCHASES

On May 6, 2021, the Corporation announced an increase in the amount of its dividend, as well as a change in the frequency of its dividend payment from monthly to quarterly, effective with its June 2021 dividend payment. The Corporation also increased its dividend for September and December 2021, which resulted in an increase of 37%, on an annualized basis, during 2021.

The Corporation renewed its normal course issuer bid on August 16, 2021 to purchase up to 10% of the public float (within the meaning under the TSX rules) during a 12-month period. During 2021, Enerplus repurchased an aggregate of approximately 12.9 million Common Shares for aggregate proceeds of approximately $123.2 million.  

Developments in 2022

ASSET SALES

On February 2, 2022, Enerplus announced its plans to initiate a divestment process for its Canadian assets. On October 31, 2022 Enerplus completed the sale of its Ante Creek and Medicine Hat assets, together with broad interests west of the fifth and sixth meridians of Alberta, for total consideration of $104.4 million (CDN$142.2 million), prior to closing adjustments. On December 19, 2022, Enerplus completed the sale of substantially all of its remaining Canadian assets for total consideration of $174.5 million (CDN$238.2 million), prior to closing adjustments. After purchase price adjustments, proceeds from the two divestments were $213.0 million.

Notwithstanding the sale of substantially all of its Canadian assets in 2022, the Corporation continues to maintain a Canadian head office. See "Business of the Corporation – Summary of Principal Production Locations" and "Business of the Corporation – Description of Properties".

FINANCING

On February 23, 2022 Enerplus converted the Term Facility into a revolving bank credit facility with no other amendments, which was subsequently, on November 3, 2022, converted into the $365 million SLL Credit Facility maturing on October 31, 2025. Also, on November 3, 2022 the $900 million SLL Credit Facility was extended with $50 million maturing on October 31, 2025 and $850 million maturing on October 31, 2026.

See "Description of Capital Structure" and "Material Contracts and Documents Affecting the Rights of Securityholders".

SHAREHOLDER RETURNS – DIVIDEND & SHARE REPURCHASES

During 2022, the Corporation changed its dividend declaration amount to US dollars (from Canadian dollars) and increased its quarterly dividend by 67% to US$0.055 per share.

In August 2022, the Corporation renewed its normal course issuer bid to purchase up to 10% of the "public float" (within the meaning under the TSX rules) during a 12-month period commencing on August 16, 2022. During 2022, Enerplus repurchased an aggregate of approximately 27.9 million Common Shares at an aggregate cost of approximately $410.9 million. From January 1, 2023 to February 22, 2023, the Corporation repurchased an additional approximately 1.4 million Common Shares for an aggregate cost of approximately $23.7 million.

Business of the Corporation

OVERVIEW

Substantially all of the Corporation's crude oil and natural gas property interests at December 31, 2022 are located in the United States, in North Dakota, Colorado and Pennsylvania. Capital spending on the Corporation’s assets in 2022 totaled $432.0 million. Substantially all of the Corporation’s Canadian assets were sold during 2022 (see "General Development of the Business—Developments in the Past Three Years—Developments in 2022—Asset Sales").

Capital spending on the Corporation's Williston Basin and Colorado assets totaled $368.0 million during 2022. Capital spending on the Corporation's natural gas interests in northeast Pennsylvania was $57.6 million. Capital spending in Canada totaled approximately $6.1 million.

In 2022, the Corporation spent $17.4 million on abandonment and reclamation activities, $11.9 million of which related to the abandonment of its Tommy Lakes asset in British Columbia with the majority of the remaining $5.5 million spent across various other Canadian properties.

12    ENERPLUS 2022 ANNUAL INFORMATION FORM

Production volumes for the year ended December 31, 2022 from the Corporation's properties consisted of 61% crude oil and NGLs and 39% natural gas, on a BOE/day basis. The Corporation's major producing properties generally have related field facilities and infrastructure to accommodate its production. The Corporation's 2022 average daily production was 100,326 BOE/day, comprised of: 47,511 bbls/day of tight oil, 2,556 bbls/day of heavy oil, 1,950 bbls/day of light and medium oil (a total of 52,017 bbls/day of crude oil), 9,681 bbls/day of NGLs and 231,770 Mcf/day of natural gas (includes 225,845 Mcf/day of shale gas). Production increased approximately 9% compared to 2021 average daily production of 92,221 BOE/day, comprised of: 42,981 bbls/day of tight oil, 3,302 bbls/day of heavy oil, 2,231 bbls/day of light and medium oil (totaling 48,514 bbls/day of crude oil), 7,823 bbls/day of NGLs and 215,304 Mcf/day of natural gas (includes 207,486 Mcf/day of shale gas). See "Summary of Principal Production Locations". The increase in average daily production in 2022 compared to 2021 is largely attributable to strong well performance from Enerplus' Bakken assets, including the full year contribution from its 2021 acquisitions, and higher completions activity in the Marcellus.

The Corporation's 2022 production in the United States was approximately 95% of its total production, with the remaining 5% from Canada. Approximately 66% of the Corporation's 2022 production was operated by the Corporation, with the remainder operated by industry partners.

At December 31, 2022, the crude oil and natural gas property interests held by the Corporation were estimated to contain total proved plus probable gross reserves of 317.1 MMbbls of tight oil, 56.3 MMbbls of NGLs and 1,365.9 Bcf of shale gas, for a total of 601.1 MMBOE. The Corporation's proved reserves represented approximately 65% of total proved plus probable reserves, with approximately 62% 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, 2022, (ii) all production information represents the Corporation's net production from these properties, which is calculated after deduction of royalty interests owned by others and including the Corporation's royalty interests, and (iii) except for disclosure in Appendix B, 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, 2022, on a BOE basis, approximately 95% of the Corporation's gross production was derived from the United States (64% from North Dakota, 26% from Pennsylvania and 5% from Colorado) and 5% from Canada (4% from Alberta and 1% from Saskatchewan).

The following table describes the average daily gross production from the Corporation's principal producing properties and regions during the year ended December 31, 2022.

2022 Average Daily Gross Production from Principal Properties and Regions⁽¹⁾

	Products
	Crude Oil
					Conventional
	Light and				Natural	Shale
Property/Region	Medium	Heavy	Tight	NGLs	Gas	Gas	Total, Gross
	(bbls/day)	(bbls/day)	(bbls/day)	(bbls/day)	(Mcf/day)	(Mcf/day)	(BOE/day)
United States
North Dakota	-	-	58,041	11,583	-	69,335	81,180
Marcellus, Pennsylvania	-	-	-	-	-	211,168	35,195
DJ Basin, Colorado	-	-	996	131	-	881	1,274
Total United States	-	-	59,037	11,714	-	281,384	117,649
Canada(2)
Freda Lake, Saskatchewan	1,945	-	-	-	-	-	1,945
Medicine Hat Glauconitic "C" Unit, Alberta	-	1,464	-	-	213	-	1,500
Giltedge, Alberta	-	1,386	-	-	213	-	1,422
Ante Creek, Alberta	710	-	-	112	837	-	962
Other Canada	25	468	-	216	4,506	195	1,490
Total Canada	2,680	3,318	-	328	5,769	195	7,319
Total	2,680	3,318	59,037	12,042	5,769	281,579	124,968

ENERPLUS 2022 ANNUAL INFORMATION FORM    13

(1) The gross production volumes in this table will not match certain of the production volumes presented elsewhere in this Annual Information Form, which are presented on a net basis. See “Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Disclosure of Reserves and Production Information” in this Annual Information Form.

(2) During 2022, Enerplus sold substantially all of its Canadian assets. See "General Development of the Business – Developments in the Past Three Years – Developments in 2022". 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 $432.0 million in its capital spending program during 2022, with 87% directed to crude oil-related projects, approximately 43% higher than its 2021 capital spending program of $302.3 million. Capital spending during 2022 was focused primarily in the Corporation’s North Dakota Bakken crude oil property (with investment of $365.2 million). The Corporation’s Marcellus non-operated assets received capital investment of $57.6 million during the year. The remaining $9.2 million of capital was spent across the Corporation’s other assets, including approximately $6.1 million in Canada.

In the financial year ended December 31, 2022, 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
	(US$ in millions)
United States	$	21.3	$	-	$	1.4	$	424.5
Canada		1.2		-		0.2		5.9
Total	$	22.5	$	-	$	1.6	$	430.4

For further information regarding the Corporation's properties and its 2022 exploration and development activities, see "Description of Properties", below.

Based on a budgeted commodity price of $80 per barrel WTI for crude oil, $3.50 per Mcf NYMEX for natural gas, a Bakken differential of $0.75 per bbl above WTI, a Marcellus differential of $0.75 per Mcf below NYMEX and a foreign exchange rate of CDN/USD 0.75, the Corporation's 2023 exploration and development capital spending is estimated to be between $500 to $550 million.

The Corporation intends to finance its 2023 capital spending program with cash, internally generated cash flow and/or debt. The Corporation will review its 2023 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".

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, 2022, all of which were located in the United States. Wells have been classified in accordance with the definitions of such terms in NI 51-101.

	Development Wells		Exploratory Wells
Category of Well	Gross	Net	Gross	Net
Crude oil wells	103	46.2	-	-
Natural gas wells	81	5.5	-	-
Service wells	-	-	-	-
Dry and abandoned wells	-	-	-	-
Total	184	51.7	-	-

For a description of the Corporation's 2023 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, 2022, 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 crude oil

14    ENERPLUS 2022 ANNUAL INFORMATION FORM

and natural gas, a well is categorized as a crude oil well or a natural gas well based upon the proportion of crude oil or natural gas production that constitutes the majority of production from that well.

	Producing Wells				Non-Producing Wells				Unproved Properties
	Crude Oil		Natural Gas		Crude Oil		Natural Gas		(acres)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
United States
Colorado	30	14.1	-	-	17	0.9	-	-	23,480	21,528
North Dakota	1,333	774.9	-	-	31	17.7	-	-	5,023	2,081
Pennsylvania	-	-	1,132	111.0	-	-	47	5.7	22,685	5,877
Total	1,363	789.0	1,132	111.0	48	18.6	47	5.7	51,188	29,486

The Corporation expects its rights to explore, develop and exploit on approximately 648 net acres of its unproved properties to expire in the ordinary course prior to December 31, 2023. 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 unusually 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 asset retirement disclosures in the Financial Statements.    

DESCRIPTION OF PROPERTIES

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

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

Crude Oil Properties

OVERVIEW

The Corporation’s primary crude oil properties are located in the Bakken in North Dakota and the Wattenberg Field in Weld County of the DJ Basin of Colorado. The Corporation spent $376.7 million on its crude oil assets in 2022, including the Canadian waterflood assets which were sold during the year.

The Corporation has approximately 235,600 net acres of land primarily on the Fort Berthold Indian Reservation ("FBIR") as well as Williams and Dunn Counties. On a production basis, Enerplus operates approximately 92% of its North Dakota asset. The Corporation’s Bakken properties produce a light sweet crude oil (42° API), with some associated natural gas and NGLs, from both the Bakken and Three Forks formations. Production in the Bakken averaged 65,370 BOE/day in 2022, which consisted of 46,706 bbls/day of tight oil, 9,333 bbls/day of NGLs and 55,987 Mcf/day of shale gas. During 2022, the Corporation spent $365.2 million on its operated and non-operated assets in North Dakota, and including the assets acquired pursuant to the Bruin Acquisition and Dunn County Acquisition. This included drilling 45.7 net horizontal wells (38.8 operated and 7.0 non-operated), targeting the Bakken and Three Forks formations (all of which were long lateral wells), with 43.3 net wells brought on-stream (35.5 operated and 7.8 non-operated). At the end of 2022, the Corporation had 13.3 net operated drilled uncompleted wells in North Dakota.

The Corporation holds approximately 32,950 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 2022 was $2.8 million and focused on completing and bringing 0.3 net operated wells onstream. Average annual production for 2022 was 1,026 BOE/day (78% tight oil). At the end of 2022, the Corporation had no operated drilled uncompleted wells in Colorado.

Overall, the Corporation's crude oil properties produced an average of 72,168 BOE/day in 2022, an increase of 8% from 2021 primarily due to the benefit of the 2021 acquisitions. On a BOE basis, production from crude oil properties represented 72% of the Corporation's 2022 average daily production of 100,326 BOE/day.

ENERPLUS 2022 ANNUAL INFORMATION FORM    15

Approximately 51.0 MMBOE of gross proved plus probable reserves were added in North Dakota during 2022, including extensions, acquisitions, technical revisions and economic factors. After adjusting for 2022 gross production of 29.6 MMBOE, total gross proved plus probable reserves associated with this property as at December 31, 2022 were 424.7 MMBOE, approximately 5% greater than at December 31, 2021.

The Corporation had 426.8 MMBOE of gross proved plus probable reserves associated with its crude oil assets at December 31, 2022, representing approximately 71% of its total gross 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 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.

Natural Gas Properties

OVERVIEW

The Corporation'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 32,500 net acres. The Corporation's Marcellus shale gas production averaged approximately 169 MMcf/day in 2022, representing approximately 28% of the Corporation's total average daily production of 100,326 BOE/day.

In 2022, $57.6 million was invested in the Corporation's non-operated Marcellus interests. The Corporation participated in the drilling of 5.5 net wells and 6.8 net wells were brought on-stream.

Gross proved plus probable Marcellus shale gas reserves were 1,045.8 Bcf as at December 31, 2022, a decrease of 5.3 Bcf from 2021, and represented approximately 29% of the Corporation's total gross 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.

16    ENERPLUS 2022 ANNUAL INFORMATION FORM

QUARTERLY PRODUCTION HISTORY⁽¹⁾

The following table sets forth the Corporation's average daily production volumes, on a gross basis, by product type, for each fiscal quarter in 2022 and for the entire year, separately for production in Canada and the United States, and in total.

	Year Ended December 31, 2022
	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)	52,617	53,630	66,088	63,618	59,037
Total crude oil (bbls/day)	52,617	53,630	66,088	63,618	59,037
Natural gas liquids (bbls/day)	10,017	10,340	13,208	13,238	11,714
Total liquids (bbls/day)	62,634	63,970	79,296	76,856	70,751
Conventional natural gas (Mcf/day)	-	-	-	-	-
Shale gas (Mcf/day)	261,456	269,567	286,227	307,720	281,384
Total United States (BOE/day)	106,210	108,898	127,001	128,143	117,649
Canada
Light and medium oil (bbls/day)	2,992	2,913	2,845	1,977	2,680
Heavy oil (bbls/day)	3,803	3,824	3,529	2,130	3,318
Tight oil (bbls/day)	-	-	-	-	-
Total crude oil (bbls/day)	6,795	6,737	6,374	4,107	5,998
Natural gas liquids (bbls/day)	428	407	386	93	328
Total liquids (bbls/day)	7,223	7,144	6,760	4,200	6,326
Conventional natural gas (Mcf/day)	7,380	7,310	6,799	1,641	5,769
Shale gas (Mcf/day)	242	215	198	125	195
Total Canada (BOE/day)	8,493	8,398	7,926	4,494	7,319
Total
Light and medium oil (bbls/day)	2,992	2,913	2,845	1,977	2,680
Heavy oil (bbls/day)	3,803	3,824	3,529	2,130	3,318
Tight oil (bbls/day)	52,617	53,630	66,088	63,618	59,037
Total crude oil (bbls/day)	59,412	60,367	72,462	67,725	65,035
Natural gas liquids (bbls/day)	10,445	10,747	13,594	13,331	12,042
Total liquids (bbls/day)	69,857	71,114	86,056	81,056	77,077
Conventional natural gas (Mcf/day)	7,380	7,310	6,799	1,641	5,769
Shale gas (Mcf/day)	261,698	269,782	286,425	307,845	281,579
Total (BOE/day)	114,703	117,296	134,927	132,637	124,968

(1) The gross production volumes in this table will not match certain of the production volumes presented elsewhere in this Annual Information Form, which are presented on a net basis. See “Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Disclosure of Reserves and Production Information” in this Annual Information Form.

ENERPLUS 2022 ANNUAL INFORMATION FORM    17

QUARTERLY NETBACK HISTORY

The following tables set forth the Corporation's average netbacks received for each fiscal quarter in 2022 and for the entire year, separately for gross 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, 2022
	First		Second		Third		Fourth
Light and Medium Crude Oil (US$ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
Canada (~2% of total Company production)
Sales price(1)	$	83.56	$	100.52	$	81.42	$	73.90	$	85.79
Transportation		(0.80)		(0.61)		(0.86)		(0.87)		(0.78)
Royalties(2)		(23.92)		(30.13)		(24.25)		(18.41)		(24.67)
Production costs(3)		(12.51)		(12.68)		(14.41)		(7.41)		(12.12)
Netback	$	46.33	$	57.10	$	41.90	$	47.21	$	48.22

	Year Ended December 31, 2022
	First		Second		Third		Fourth
Heavy Oil (US$ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
Canada (~3% of total Company production)
Sales price(1)	$	74.86	$	92.74	$	70.88	$	54.36	$	75.61
Transportation		(1.74)		(1.88)		(1.92)		(4.11)		(2.21)
Royalties(2)		(16.76)		(23.71)		(18.79)		(13.23)		(18.73)
Production costs(3)		(15.84)		(19.41)		(22.32)		(18.41)		(19.02)
Netback	$	40.52	$	47.74	$	27.85	$	18.61	$	35.65

	Year Ended December 31, 2022
	First		Second		Third		Fourth
Tight Oil (US$ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
United States (~47% of total Company production)
Sales price(1)	$	93.86	$	110.31	$	94.14	$	84.48	$	95.12
Transportation		(4.43)		(4.56)		(4.24)		(3.99)		(4.29)
Royalties(2)		(25.51)		(30.06)		(26.64)		(22.89)		(26.15)
Production costs(3)		(14.71)		(14.36)		(14.83)		(14.88)		(14.71)
Netback	$	49.21	$	61.33	$	48.43	$	42.72	$	49.97

	Year Ended December 31, 2022
	First		Second		Third		Fourth
Natural Gas Liquids (US$ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
United States (~9% of total Company production)
Sales price(1)	$	38.06	$	33.56	$	32.01	$	22.30	$	30.86
Transportation		(0.39)		(0.38)		(0.39)		(0.41)		(0.39)
Royalties(2)		(8.04)		(7.54)		(6.70)		(4.79)		(6.62)
Production costs(3)		—		—		—		—		—
Netback	$	29.63	$	25.64	$	24.92	$	17.10	$	23.85
Canada (<1% of total Company production)
Sales price(1)	$	55.56	$	68.11	$	55.24	$	22.34	$	56.99
Transportation		(2.83)		(2.27)		(2.28)		(6.91)		(2.78)
Royalties(2)		(19.39)		(21.70)		(17.29)		13.29		(17.16)
Production costs(3)		—		—		—		—		—
Netback	$	33.34	$	44.14	$	35.67	$	28.72	$	37.05

	Year Ended December 31, 2022
	First		Second		Third		Fourth
Conventional Natural Gas (US$ per Mcf)	Quarter		Quarter		Quarter		Quarter		Annual
Canada (<1% of total Company production)
Sales price(1)	$	3.93	$	6.13	$	3.25	$	4.15	$	4.44
Transportation		(0.39)		(0.39)		(0.37)		(0.78)		(0.42)
Royalties(2)		0.13		0.42		0.76		2.60		0.59
Production costs(3)		(4.19)		(1.33)		(2.15)		(5.20)		(2.75)
Netback	$	(0.52)	$	4.83	$	1.49	$	0.77	$	1.86

18    ENERPLUS 2022 ANNUAL INFORMATION FORM

	Year Ended December 31, 2022
	First		Second		Third		Fourth
Shale Gas (US$ per Mcf)	Quarter		Quarter		Quarter		Quarter		Annual
United States (~38% of total Company production)
Sales price(1)	$	4.70	$	6.20	$	6.71	$	4.87	$	5.62
Transportation		(0.56)		(0.57)		(0.53)		(0.52)		(0.54)
Royalties(2)		(1.01)		(1.35)		(1.46)		(1.07)		(1.22)
Production costs(3)		(0.08)		(0.09)		(0.05)		(0.08)		(0.08)
Netback	$	3.05	$	4.19	$	4.67	$	3.20	$	3.78
Canada (<1% of total Company production)
Sales price(1)	$	3.66	$	5.31	$	4.20	$	2.78	$	4.11
Transportation		(0.36)		(0.35)		(0.33)		(0.52)		(0.38)
Royalties(2)		0.35		0.96		0.50		1.03		0.67
Production costs(3)		(0.89)		(1.56)		(1.60)		(1.35)		(1.33)
Netback	$	2.76	$	4.36	$	2.77	$	1.94	$	3.07

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.

ENERPLUS 2022 ANNUAL INFORMATION FORM    19

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 spending and forecasted net income, the Corporation expects to pay U.S. cash taxes of approximately 5% to 6% of adjusted funds flow before tax in 2023. The Corporation does not anticipate paying cash taxes in Canada until 2027. 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, including exports, and interpretations of those laws and trade agreements, may adversely affect the Corporation and its securityholders".

For additional information, see Notes 2 and 14 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 2022 ANNUAL INFORMATION FORM

MARKETING ARRANGEMENTS AND FORWARD CONTRACTS

Crude Oil and NGLs

The Corporation’s realized crude oil price averaged $93.63/bbl and $30.70/bbl for its NGLs for the year ended December 31, 2022, excluding transportation costs and the effects of commodity derivative instruments, compared to $65.89/bbl for its crude oil and $29.51/bbl for its NGLs for the year ended December 31, 2021.

The Corporation's crude oil is marketed to a diverse portfolio of intermediaries and end users, generally on negotiated contracts ranging from 30 days up to multiple years. The Corporation transports its 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 2022, the Corporation received an average price differential for its U.S. Bakken crude oil of $1.09/bbl above WTI, compared to an average of $2.15/bbl below WTI in 2021. The Corporation has access to firm transportation of 22,550 gross barrels per day on the Dakota Access Pipeline ("DAPL"), via its own contracted service and with third party capacity, 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 crude oil production volumes are marketed on its behalf by midstream companies in North Dakota and Colorado and prices are linked to the monthly spot markets for NGLs. See "Risk Factors – Sales Pipelines and Rail Transportation Systems".

Natural Gas

In marketing its natural gas production, the Corporation strives for a mix of contracts and customers. In 2022, 73% of the Corporation's natural gas production originated from its non-operated Marcellus interest in northeast Pennsylvania. The Corporation delivered approximately 56% of its Marcellus production in 2022 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 47 MMcf/day of natural gas production in the Marcellus for terms of up to approximately 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 65 MMcf/day, with terms ending between 2023 and 2036.

The Corporation’s realized natural gas price averaged $5.51/Mcf in 2022, excluding transportation costs and the effects of commodity derivative instruments, compared to $2.94/Mcf in 2021. In 2022, the Corporation received an average price differential for its U.S. Marcellus shale gas production of $0.72/Mcf below NYMEX compared to an average of $0.81/Mcf below NYMEX in 2021. Approximately 27% of the Corporation's natural gas production was associated natural gas production from its crude oil operations in North Dakota and the DJ Basin. The Corporation does not market these volumes directly, as they are marketed on Enerplus' behalf by midstream companies.

Future Commitments and Forward Contracts

The Corporation may use various types of derivative financial instruments and fixed price physical sales contracts to manage the risk related to fluctuating commodity prices. Absent such hedging activities, all of the crude oil and NGLs and the majority of natural gas production of the Corporation is sold into the open market at prevailing market prices, which exposes the Corporation to the risks associated with commodity price fluctuations and foreign exchange rates. See "Risk Factors". Information regarding the Corporation's financial instruments is contained in Note 16 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 2022 ANNUAL INFORMATION FORM    21

Oil and Natural Gas Reserves

SUMMARY OF RESERVES

As at December 31, 2022, all of the Corporation's crude oil and natural gas reserves were associated with its properties located in the United States. The Corporation’s reserves have been evaluated in accordance with NI 51-101. Independent reserves evaluations have been conducted on properties comprising 100% 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 all of the Corporation's reserves associated with the Corporation's properties located in North Dakota and Colorado. McDaniel used the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2023 to prepare its report.

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, 2023 to prepare its report.

The following sections and tables summarize, as at December 31, 2022, 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, 2021 to December 31, 2022, 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 spending, 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.

22    ENERPLUS 2022 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, 2022, using forecast price and cost cases.

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

As of December 31, 2022

			Natural Gas
RESERVES	Tight Oil		Liquids		Shale Gas		Total
CATEGORY	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)	(MBOE)
Proved
Proved Developed Producing	92,788	74,632	18,839	15,172	756,966	607,337	237,789	191,027
Proved Developed Non-Producing	2,925	2,352	413	332	4,131	3,334	4,026	3,240
Proved Undeveloped	84,560	67,699	13,340	10,676	313,106	252,747	150,085	120,500
Total Proved	180,273	144,684	32,592	26,179	1,074,204	863,419	391,899	314,766
Probable	136,863	109,661	23,743	19,036	291,705	237,802	209,224	168,331
Total Proved Plus Probable	317,136	254,345	56,335	45,215	1,365,908	1,101,221	601,123	483,097

Summary of Net Present Value of Future Net Revenue

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

As of December 31, 2022

	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 US$ millions)										US$/BOE
Proved
Proved Developed Producing	4,622	3,712	3,126	2,726	2,436	3,724	3,013	2,540	2,213	1,976		$16.37
Proved Developed Non‑Producing	103	83	69	58	50	78	63	52	44	38		$21.15
Proved Undeveloped	2,801	2,036	1,545	1,209	968	2,118	1,538	1,163	907	723		$12.82
Total Proved	7,526	5,831	4,740	3,994	3,455	5,919	4,614	3,755	3,164	2,737		$15.06
Probable	5,407	3,337	2,258	1,631	1,238	4,099	2,511	1,681	1,203	904		$13.41
Total Proved Plus Probable	12,934	9,169	6,998	5,625	4,693	10,019	7,125	5,436	4,366	3,641		$14.49

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 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, 2023 (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:

	CRUDE OIL	NATURAL GAS
		U.S. Henry
		Hub	Inflation	Exchange
Year	WTI(1)	Gas Price	Rate	Rate
	($US/bbl)	($US/MMbtu)	(%/year)	($US/$Cdn)
2023	80.33	4.74	0.0	0.745
2024	78.50	4.50	2.3	0.765
2025	76.95	4.31	2.0	0.768
2026	77.61	4.40	2.0	0.772
2027	79.16	4.49	2.0	0.775
2028	80.74	4.58	2.0	0.775
2029	82.36	4.67	2.0	0.775
2030	84.00	4.76	2.0	0.775
2031	85.69	4.86	2.0	0.775
2032	87.40	4.95	2.0	0.775
2033	89.15	5.05	2.0	0.775
2034	90.93	5.15	2.0	0.775
2035	92.75	5.26	2.0	0.775
2036	94.61	5.36	2.0	0.775
2037	96.50	5.47	2.0	0.775
Thereafter	(2)	(2)	2.0	0.775

Notes:   

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

(2) Escalation is approximately 2% per year thereafter

In 2022, the Corporation received a weighted average price (before transportation costs and the effects of commodity derivative instruments) of $93.63/bbl for crude oil, $30.70/bbl for natural gas liquids and $5.51/Mcf for natural gas.

ENERPLUS 2022 ANNUAL INFORMATION FORM    23

UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2022, 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 US$ millions)
Proved Reserves	18,495	4,814	4,270	1,553	331	7,526	1,607	5,919
Proved Plus Probable Reserves	31,787	8,411	6,985	3,038	420	12,934	2,915	10,019

Notes:

(1) Royalties include any net profits interests paid

(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 deductionsand appropriate federal and state tax rates.

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, 2022, 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 US$ thousands)		(US$/bbl; US$/Mcf)
Proved Reserves	Tight Oil(2)	$	3,871,047	$	26.76
	Shale Gas(3)		868,900		1.23
	Total	$	4,739,947
Proved Plus Probable Reserves	Tight Oil(2)	$	6,048,905	$	23.78
	Shale Gas(3)		949,062		1.13
	Total	$	6,997,967

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) No by-product oil or NGLs are associated with shale gas.

ESTIMATED PRODUCTION FOR GROSS RESERVES ESTIMATES

The volume of total production for the Corporation estimated for 2023 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual 2023 production (including from North Dakota 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
	Estimated 2023		Estimated 2023
	Aggregate		Average Daily
Product Type	Production		Production
Crude Oil
Tight Oil	22,744	Mbbls	62,312	bbls/day
Total Crude Oil	22,744	Mbbls	62,312	bbls/day
Natural Gas Liquids	3,850	Mbbls	10,547	bbls/day
Total Liquids	26,594	Mbbls	72,859	bbls/day
Shale Gas	107,908	MMcf	295,638	Mcf/day
Total	44,578	MBOE	122,132	BOE/day

24    ENERPLUS 2022 ANNUAL INFORMATION FORM

	Gross Probable Reserves
	Estimated 2023		Estimated 2023
	Aggregate		Average Daily
Product Type	Production		Production
Crude Oil
Tight Oil	2,083	Mbbls	5,708	bbls/day
Total Crude Oil	2,083	Mbbls	5,708	bbls/day
Natural Gas Liquids	351	Mbbls	963	bbls/day
Total Liquids	2,435	Mbbls	6,670	bbls/day
Shale Gas	3,583	MMcf	9,817	Mcf/day
Total	3,032	MBOE	8,307	BOE/day

The tables below set forth McDaniel's and NSAI’s estimated 2023 production for the Corporation's North Dakota, United States properties, 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 2023 production.

	Gross Proved Reserves
	North Dakota				Marcellus
	Estimated 2023		Estimated 2023		Estimated 2023		Estimated 2023
	Aggregate		Average Daily		Aggregate		Average Daily
Product Type	Production		Production		Production		Production
Crude Oil
Tight Oil	22,505	Mbbls	61,659	bbls/day	-	Mbbls	-	bbls/day
Total Crude Oil	22,505	Mbbls	61,659	bbls/day	-	Mbbls	-	bbls/day
Natural Gas Liquids	3,814	Mbbls	10,448	bbls/day	-	Mbbls	-	bbls/day
Total Liquids	26,319	Mbbls	72,107	bbls/day	-	Mbbls	-	bbls/day
Shale Gas	22,922	MMcf	62,800	Mcf/day	84,743	MMcf	232,172	Mcf/day
Total	30,139	MBOE	82,573	BOE/day	14,124	MBOE	38,695	BOE/day

	Gross Probable Reserves
	North Dakota				Marcellus
	Estimated 2023		Estimated 2023		Estimated 2023		Estimated 2023
	Aggregate		Average Daily		Aggregate		Average Daily
Product Type	Production		Production		Production		Production
Crude Oil
Tight Oil	2,072	Mbbls	5,676	bbls/day	-	Mbbls	-	bbls/day
Total Crude Oil	2,072	Mbbls	5,676	bbls/day	-	Mbbls	-	bbls/day
Natural Gas Liquids	350	Mbbls	958	bbls/day	-	Mbbls	-	bbls/day
Total Liquids	2,422	Mbbls	6,634	bbls/day	-	Mbbls	-	bbls/day
Shale Gas	2,102	MMcf	5,760	Mcf/day	1,470	MMcf	4,026	Mcf/day
Total	2,772	MBOE	7,594	BOE/day	245	MBOE	671	BOE/day

ENERPLUS 2022 ANNUAL INFORMATION FORM    25

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".

			Proved Plus
	Proved Reserves		Probable Reserves
		Discounted		Discounted
Year	Undiscounted	at 10%/year	Undiscounted	at 10%/year
	(in US$ millions)
2023	484	462	485	463
2024	347	304	347	304
2025	472	372	472	372
2026	248	181	316	229
2027	1	1	463	305
2028	0	-	379	227
Remainder	0	-	574	308
Total	1,553	1,320	3,038	2,207

RECONCILIATION OF RESERVES

Overview

The Corporation's total gross proved plus probable reserves at December 31, 2022 were 601.1 MMBOE, a decrease of 2% from year-end 2021. The Corporation's gross proved plus probable crude oil and NGLs reserves were 373.5 MMBOE and represented 62% of total proved plus probable gross reserves, a decrease of 3% from year-end 2021. The Corporation replaced approximately 139% of its 2022 gross production through its exploration and development program, adding 63.3 MMBOE of proved plus probable reserves, including revisions and economic factors. Of the Corporation’s 63.3 MMBOE of proved plus probable additions, including revisions and economic factors, 51.0 MMBOE are attributed to the North Dakota properties and 12.0 MMBOE (71.7 Bcf) to the Marcellus shale gas property.

In 2022, the Corporation sold substantially all of its Canadian assets, which included all Canadian assets that had reserves assigned to them in 2021.

26    ENERPLUS 2022 ANNUAL INFORMATION FORM

The following tables reconcile the Corporation's gross crude oil and natural gas reserves from December 31, 2021 to December 31, 2022, by country and in total, using forecast prices and costs. Certain columns may not add due to rounding.

UNITED STATES GROSS 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, 2021	-	-	-	-	-	-	178,600	120,746	299,346	33,208	22,102	55,310
Acquisitions	-	-	-	-	-	-	290	72	363	31	7	38
Dispositions	-	-	-	-	-	-	(1,432)	(350)	(1,782)	(158)	(47)	(204)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	19,235	24,216	43,451	3,002	4,016	7,018
Economic Factors	-	-	-	-	-	-	4,963	2,131	7,094	1,005	409	1,414
Technical Revisions	-	-	-	-	-	-	165	(9,951)	(9,786)	(220)	(2,744)	(2,965)
Production	-	-	-	-	-	-	(21,549)	-	(21,549)	(4,276)	-	(4,276)
December 31, 2022	-	-	-	-	-	-	180,273	136,863	317,136	32,592	23,743	56,335

	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, 2021	-	-	-	1,070,154	297,339	1,367,493	390,168	192,404	582,572
Acquisitions	-	-	-	148	35	183	346	85	431
Dispositions	-	-	-	(1,381)	(413)	(1,794)	(1,820)	(465)	(2,285)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	67,503	69,832	137,336	33,488	39,871	73,358
Economic Factors	-	-	-	5,924	2,280	8,203	6,956	2,919	9,875
Technical Revisions	-	-	-	34,560	(77,368)	(42,808)	5,705	(25,590)	(19,886)
Production	-	-	-	(102,705)	-	(102,705)	(42,942)	-	(42,942)
December 31, 2022	-	-	-	1,074,204	291,704	1,365,908	391,899	209,224	601,123

CANADIAN GROSS 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, 2021	6,245	1,917	8,162	15,612	5,079	20,691	-	-	-	689	222	911
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	(5,267)	(1,917)	(7,184)	(14,401)	(5,079)	(19,480)	-	-	-	(570)	(222)	(792)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Production	(978)	-	(978)	(1,211)	-	(1,211)	-	-	-	(120)	-	(120)
December 31, 2022	-	-	-	-	-	-	-	-	-	-	-	-

	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, 2021	15,196	4,481	19,677	345	88	433	25,136	7,980	33,116
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	(13,090)	(4,481)	(17,571)	(274)	(88)	(362)	(22,465)	(7,980)	(30,445)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-
Production	(2,106)	-	(2,106)	(71)	-	(71)	(2,671)	-	(2,671)
December 31, 2022	-	-	-	-	-	-	-	-	-

ENERPLUS 2022 ANNUAL INFORMATION FORM    27

TOTAL GROSS 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, 2021	6,245	1,917	8,162	15,612	5,079	20,691	178,600	120,746	299,346	33,897	22,324	56,221
Acquisitions	-	-	-	-	-	-	290	72	363	31	7	38
Dispositions	(5,267)	(1,917)	(7,184)	(14,401)	(5,079)	(19,480)	(1,432)	(350)	(1,782)	(728)	(269)	(996)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	19,235	24,216	43,451	3,002	4,016	7,018
Economic Factors	-	-	-	-	-	-	4,963	2,131	7,094	1,005	409	1,414
Technical Revisions	-	-	-	-	-	-	165	(9,951)	(9,786)	(220)	(2,744)	(2,965)
Production	(978)	-	(978)	(1,211)	-	(1,211)	(21,549)	-	(21,549)	(4,395)	-	(4,395)
December 31, 2022	-	-	-	-	-	-	180,273	136,863	317,136	32,592	23,743	56,335

	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, 2021	15,196	4,481	19,677	1,070,500	297,427	1,367,927	415,304	200,384	615,688
Acquisitions	-	-	-	148	35	183	346	85	431
Dispositions	(13,090)	(4,481)	(17,571)	(1,655)	(501)	(2,156)	(24,286)	(8,445)	(32,731)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	67,503	69,832	137,336	33,488	39,871	73,358
Economic Factors	-	-	-	5,924	2,280	8,203	6,956	2,919	9,875
Technical Revisions	-	-	-	34,560	(77,368)	(42,808)	5,705	(25,590)	(19,886)
Production	(2,106)	-	(2,106)	(102,776)	-	(102,776)	(45,613)	-	(45,613)
December 31, 2022	-	-	-	1,074,204	291,704	1,365,908	391,899	209,224	601,123

The following tables reconcile the Corporation's net crude oil and natural gas reserves from December 31, 2021 to December 31, 2022, in total, using forecast prices and costs. Certain columns may not add due to rounding.

UNITED STATES NET OIL AND GAS RESERVES

	Light & Medium Oil (NET)			Heavy Oil (NET)			Tight Oil (NET)			Natural Gas Liquids (NET)
			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, 2021	-	-	-	-	-	-	143,365	96,717	240,082	26,669	17,706	44,375
Acquisitions	-	-	-	-	-	-	231	57	288	24	6	30
Dispositions	-	-	-	-	-	-	(1,145)	(279)	(1,425)	(126)	(37)	(163)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	15,463	19,410	34,873	2,414	3,225	5,639
Economic Factors	-	-	-	-	-	-	3,998	1,709	5,706	809	328	1,137
Technical Revisions	-	-	-	-	-	-	114	(7,953)	(7,839)	(165)	(2,191)	(2,357)
Production	-	-	-	-	-	-	(17,342)	-	(17,342)	(3,445)	-	(3,445)
December 31, 2022	-	-	-	-	-	-	144,684	109,661	254,345	26,179	19,036	45,215

	Conventional Natural Gas (NET)			Shale Gas (NET)			Total (NET)
			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, 2021	-	-	-	861,611	243,965	1,105,576	313,636	155,084	468,720
Acquisitions	-	-	-	143	34	177	278	69	347
Dispositions	-	-	-	(1,105)	(330)	(1,435)	(1,456)	(372)	(1,827)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	54,910	56,228	111,138	27,029	32,007	59,035
Economic Factors	-	-	-	(356)	(524)	(880)	4,748	1,949	6,697
Technical Revisions	-	-	-	30,584	(61,570)	(30,986)	5,046	(20,406)	(15,360)
Production	-	-	-	(82,368)	-	(82,368)	(34,515)	-	(34,515)
December 31, 2022	-	-	-	863,419	237,802	1,101,221	314,766	168,331	483,097

28    ENERPLUS 2022 ANNUAL INFORMATION FORM

CANADIAN NET OIL AND GAS RESERVES

	Light & Medium Oil (NET)			Heavy Oil (NET)			Tight Oil (NET)			Natural Gas Liquids (NET)
			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, 2021	5,173	1,551	6,724	13,255	4,210	17,465	-	-	-	567	196	763
Acquisitions	-	-	-	-	-	-	-	-	-	-	-	-
Dispositions	(4,461)	(1,551)	(6,012)	(12,322)	(4,210)	(16,532)	-	-	-	(479)	(196)	(675)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-	-	-	-
Production	(712)	-	(712)	(933)	-	(933)	-	-	-	(88)	-	(88)
December 31, 2022	-	-	-	-	-	-	-	-	-	-	-	-

	Conventional Natural Gas (NET)			Shale Gas (NET)			Total (NET)
			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, 2021	14,648	4,329	18,977	328	84	412	21,491	6,693	28,184
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	(12,485)	(4,329)	(16,814)	(263)	(84)	(347)	(19,387)	(6,693)	(26,080)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	-	-	-
Economic Factors	-	-	-	-	-	-	-	-	-
Technical Revisions	-	-	-	-	-	-	-	-	-
Production	(2,162)	-	(2,162)	(65)	-	(65)	(2,104)	-	(2,104)
December 31, 2022	-	-	-	-	-	-	-	-	-

TOTAL NET OIL AND GAS RESERVES

	Light & Medium Oil (NET)			Heavy Oil (NET)			Tight Oil (NET)			Natural Gas Liquids (NET)
			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, 2021	5,173	1,551	6,724	13,255	4,210	17,465	143,365	96,717	240,082	27,236	17,902	45,139
Acquisitions	-	-	-	-	-	-	231	57	288	24	6	30
Dispositions	(4,461)	(1,551)	(6,012)	(12,322)	(4,210)	(16,532)	(1,145)	(279)	(1,425)	(605)	(234)	(839)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	-	-	-	15,463	19,410	34,873	2,414	3,225	5,639
Economic Factors	-	-	-	-	-	-	3,998	1,709	5,706	809	328	1,137
Technical Revisions	-	-	-	-	-	0	114	(7,953)	(7,839)	(165)	(2,191)	(2,357)
Production	(712)	-	(712)	(933)	-	(933)	(17,342)	-	(17,342)	(3,534)	-	(3,534)
December 31, 2022	-	-	-	-	-	-	144,684	109,661	254,345	26,179	19,036	45,215

	Conventional Natural Gas (NET)			Shale Gas (NET)			Total (NET)
			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, 2021	14,648	4,329	18,977	861,939	244,049	1,105,988	335,127	161,776	496,904
Acquisitions	-	-	-	143	34	177	278	69	347
Dispositions	(12,485)	(4,329)	(16,814)	(1,368)	(414)	(1,782)	(20,843)	(7,064)	(27,907)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	-	-	-	54,910	56,228	111,138	27,029	32,007	59,035
Economic Factors	-	-	-	(356)	(524)	(880)	4,748	1,949	6,697
Technical Revisions	-	-	-	30,584	(61,570)	(30,986)	5,046	(20,406)	(15,360)
Production	(2,162)	-	(2,162)	(82,433)	-	(82,433)	(36,619)	-	(36,619)
December 31, 2022	-	-	-	863,419	237,802	1,101,221	314,766	168,331	483,097

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.

ENERPLUS 2022 ANNUAL INFORMATION FORM    29

Proved Undeveloped Reserves

	Crude Oil
			Shale
Year(1)	Tight	NGLs	Gas	Total
	(Mbbls)	(Mbbls)	(MMcf)	(MBOE)
2020	9,896	1,397	65,091	22,141
2021	28,182	4,784	108,948	51,124
2022	17,736	2,790	56,814	29,995

Note:

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

Probable Undeveloped Reserves

	Crude Oil
			Shale
Year(1)	Tight	NGLs	Gas	Total
	(Mbbls)	(Mbbls)	(MMcf)	(MBOE)
2020	6,174	687	38,195	13,227
2021	12,641	2,106	38,135	21,103
2022	23,846	3,953	68,264	39,176

Note:

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

The Corporation attributes proved and probable undeveloped reserves based on accepted engineering and geological practices as defined under NI 51-101. These practices include the determination of reserves based on the presence of commercial test rates from either production tests or drill stem tests, extensions of known accumulations based upon either geological or geophysical information, and the optimization of existing fields. The Corporation 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 expenditures 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 the United States. The Corporation intends to fund the development of its undeveloped reserves as of December 31, 2022 with cash, internally generated cash flow and/or debt. These expenditures are expected to extend the continual development of undeveloped reserves 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. With the acquisition of additional properties in North Dakota and improved commodity price forecasts, the Corporation expects to increase its activity in its North Dakota properties and has increased the gross proved plus probable undeveloped location count from 423 locations in 2021 to 494 locations as of December 31, 2022. 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 eight years.

In 2022, the Corporation continued to participate in the development of its non-operated undeveloped reserves in the Marcellus property, converting 6.2 net proved plus probable locations to developed reserves. These converted locations were replaced with additions of 7.7 net proved plus probable undeveloped locations as of December 31, 2022. 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 four years and the development of the probable undeveloped locations is scheduled to take place over the next five 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 in its Financial Statements the estimated

30    ENERPLUS 2022 ANNUAL INFORMATION FORM

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 the Corporation’s properties with assigned reserves in the United States have been reflected in reserves estimates.

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

PROVED AND PROBABLE RESERVES NOT ON PRODUCTION

The Corporation has approximately 4.8 MMBOE (4.5 MMBOE in its crude oil properties and 0.3 MMBOE (1.8 Bcf) in its natural gas properties) of proved plus probable reserves which are capable of production but which, as of December 31, 2022, were not on production. These reserves have generally been non-producing for periods ranging from a few months to four years. The majority of these volumes are associated with operated wells in North Dakota (21 wells) and Pennsylvania (2 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 by 2023.

ENERPLUS 2022 ANNUAL INFORMATION FORM    31

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 required to comply with the policies. As part of the corporate performance scorecard system, ESG targets are factored into the bonus structure applied to all executives and employees. Tying ESG performance to compensation is important to Enerplus for alignment of the Corporation’s goals. The Board has oversight for all of the Corporation's ESG activities.

Enerplus has five material ESG focus areas in scope, with accountability for each area assigned to a committee of the Board. The Board's Reserves, Safety and Social Responsibility ("RS&SR") Committee has responsibility for four of the five areas, including emissions and water management, health and safety and community engagement. Oversight of the final focus  area – culture – resides with the Board’s Compensation and Human Resources Committee. In conjunction with the current focus areas, in its assessment Enerplus is identifying both emerging and maintaining focus areas and is continuing to integrate them into the Corporation’s broader ESG strategy and management activities. The following are emerging material focus areas which have the potential to become material for Enerplus in the future: supply chain and digital technology, including cybersecurity risks. In addition, Enerplus has identified areas of previous focus which are now considered to be “maintaining” areas of focus as a result of a thorough understanding and development of good processes around them; these include board constitution and culture, as well as environmental risk management and spills and releases.

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 corporate sustainability 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 GHG and methane emissions

●Increase the efficiency of energy consumption to reduce emissions intensity

●Improve water and land use practices

●Limit the waste generated

●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

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

32    ENERPLUS 2022 ANNUAL INFORMATION FORM

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. Enerplus prepares its ESG reporting and disclosure information in accordance with the Sustainability Accounting Standards Board (SASB), the Global Reporting Initiatives (GRI) disclosure frameworks and the TCFD recommended disclosure guidelines. In addition, it also uses the International Petroleum Industry Environmental Conservation Association’s (IPIECA) Oil and gas industry guidance on voluntary sustainability reporting and, in 2022, the Corporation updated its external disclosure to include American Exploration & Production Council (AXPC) reporting. The ESG reports prepared 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.

The Corporation's anticipated risk management activities and ESG strategy will require climate change-related risks to be integrated into its long-range planning process, but we cannot predict what form this will ultimately take given the long-time horizons and evolving expectations. 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 which are climate change-related, as well as public opposition and activism—Climate change-related risks".  

Health and Safety

The Corporation's total combined (employee/contractor) recordable injury frequency rate 2022 was 0.60 per 200,000 worker hours, an increase from the rate of 0.55 recorded in 2021. The Corporation had an employee recordable injury frequency rate of 0.23 per 200,000 worker hours in 2022, in-line with 0.22 per 200,000 worker hours in 2021. The Corporation's total contractor recordable injury frequency was 0.73 per 200,000 worker hours in 2022, an increase from 0.66 injuries per 200,000 worker hours in 2021. The Corporation recorded one lost-time injury in 2022, compared to zero in 2021. As an ESG focus area, the Corporation has established a lost time injury frequency ("LTIF") reduction target of 25%, on average, from 2020 to 2023, relative to 2019, for its employees and contractors and since 2020, has achieved a three-year average reduction in LTIF of 80%.

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:

● Capital expenditures related to site abandonment and reclamation activities for the Corporation's Canadian and United States properties in 2022 totaled approximately $17.4 million, including $11.9 million on its Tommy Lakes asset, $4.8 million across other Canadian assets and the remainder on U.S. assets. The Corporation received 33 reclamation certificates from regulatory agencies in 2022 by returning sites to their previous equivalent land capability.

● Government regulators conducted 98 inspections of the Corporation’s field operations in the United States and Canada in 2022, a decrease compared to the prior year’s 153 government regulator inspections. The percentage of non-compliant inspections received by the Corporation in 2022 increased to 19%, compared to 8% received in 2021. The majority of non-compliant inspections were related to Canadian assets which were sold during 2022.

● 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

ENERPLUS 2022 ANNUAL INFORMATION FORM    33

any action items are recorded in the Corporation’s internal reporting platforms in order to measure compliance and ensure potential issues are addressed.

● In 2022, the Corporation completed a total of 1,540 fugitive emissions surveys for its 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. The Corporation is exploring opportunities to reduce, reuse and recycle freshwater in its North Dakota completions operations, introducing technology to treat water in real-time on location.

The Corporation is required to submit a report under the Canadian federal Greenhouse Gas Reporting Program ("GHGRP") for any facility that emitted more than 10,000 tonnes of carbon dioxide equivalent ("CO₂e") during 2021; one facility report was submitted in June 2022.

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, 2022 for the 2021 operational year. For more information on the environmental regulation applicable to the Corporation, see "Industry Conditions – Environmental Regulation".

In 2021, Scope 1 Emissions of CO₂e were 941,897 tonnes. The Corporation expects its 2022 Scope 1 Emissions (expected to be available in the second quarter of 2023) to be lower than 2021 by more than 10%. Enerplus believes it is compliant with all relevant gas capture regulatory requirements. As a part of its ESG strategy, Enerplus’ has set GHG emissions intensity reduction goals, based on Scope 1 Emissions and Scope 2 Emissions, as defined by the GHGRP. In 2022, the Corporation revised its methane emissions intensity reduction targets to a reduction of 30% by 2025, and 50% by 2030, based on a 2021 baseline. It also revised its 2030 target of a 35% reduction in Scope 1 Emissions and Scope 2 Emissions, relative to 2021 levels (set in June of 2022) due to updates to the baseline, which now reflect its 2021 acquisitions. Based on preliminary estimates, Enerplus expects its total Scope 1 and Scope 2 Emissions intensity in 2022, measured on a gross metric tonne of CO₂e per gross wellhead BOE basis, to be reduced by approximately 16%, and its methane emissions intensity to be reduced by over 10%, both relative to a 2021 baseline; positive contributions toward achieving the Corporation’s 2025 and 2030 targets. The Corporation believes achieving progress toward its emissions reduction targets is possible, for example, through the installation of vapour recovery units on all new pads and retrofits on old pads where possible, as well as the replacement of intermittent and high-bleed pneumatic devices. The Corporation spent approximately $4.5 million on this work in 2022.

In addition to the quantitative GHG emissions targets established, Enerplus continued to capture and leverage ideas being generated by employees that focused on reducing its GHG emissions in order to continue to meet its ongoing environmental obligations and achieve progress toward its ESG goals. To facilitate this, the Corporation is committed to, and has budgeted a portion of its capital expenditures to ideas that get approved as active projects. In 2021, Enerplus established an internal, executive-led working committee that meets bi-weekly and reviews task force driven assessments. This working committee also reviews the status of funded, active projects. In addition, the Board's RS&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.  

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 corporate sustainability and ESG performance. For more information on the Corporation’s 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 commissions periodic 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

34    ENERPLUS 2022 ANNUAL INFORMATION FORM

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.

PERSONNEL

As at December 31, 2022, the Corporation employed a total of 379 persons, including full-time benefit employees and payroll consultants, 152 of whom were in Canada and 227 of whom were in the United States.

ENERPLUS 2022 ANNUAL INFORMATION FORM    35

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 $203.2 million principal amounts were outstanding at December 31, 2022. Certain terms of the Senior Unsecured Notes are summarized below:

	Original	Remaining	Coupon		Interest
Issue Date	Principal	Principal	Rate		Payment Dates	Maturity Date	Term
September 3, 2014	US$200 million	US$84 million	3.79	%	March 3 and September 3	September 3, 2026	Remaining principal payments required in four equal annual installments beginning September 3, 2023
May 15, 2012	US$355 million	US$119.2 million	4.40	%	May 15 and November 15	May 15, 2024	Remaining principal payments required in two equal annual installments beginning May 15, 2023

For additional information see "Material Contracts and Documents Affecting the Rights of Securityholders". See also Note 8 to the Financial Statements.

SLL CREDIT FACILITIES

As at December 31, 2022, the Corporation had $56.3 million drawn on its $900 million SLL Credit Facility, and was undrawn on its $365 million SLL Credit Facility. The $365 million SLL Credit Facility matures on October 31, 2025; $50 million and $850 million of the $900 million SLL Credit Facility mature on October 31, 2025 and October 31, 2026, respectively. The SLL Credit Facilities incorporate ESG-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus' sustainability performance targets ("SPT") are exceeded or missed. The SPTs are based on

36    ENERPLUS 2022 ANNUAL INFORMATION FORM

ESG goals focused on Scope 1 and Scope 2 GHG emissions intensity, freshwater usage and LTIF reductions, relative to the applicable 2019 and 2021 baseline data.

For a description of the SLL Credit Facilities, see disclosure under the heading “Liquidity and Capital Resources” in the MD&A and Note 8 to the Corporation's Financial Statements, which are incorporated by reference into this Annual Information Form. See also "Material Contracts and Documents Affecting the Rights of Securityholders".

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 quarterly dividends to holders of Common Shares. The dividend payment dates are on or about the 15th day each March, June, September and December and the dividend record dates are on or about the last business day of the calendar month preceding the dividend payment date. However, any decision to pay dividends on the Common Shares will be made by the Corporation's board of directors on the basis of the relevant conditions existing at such future time, and there can be no guarantee that the Corporation will maintain its current dividend policy. Dividend amounts 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. Cash dividends are declared in US dollars, however, may be paid in Canadian dollars for shareholders who have elected to receive such. These payments are converted to Canadian dollars based upon the exchange rate closer to the dividend payment date. As such, certain shareholders are subject to foreign exchange rate risk on such payments.

The Corporation declared a monthly dividend of CDN$0.01 per share in 2020. In 2021, the Corporation declared and paid a monthly divided of CDN$0.01 per share in January through May. In May of 2021, the Corporation announced a transition to a quarterly dividend of CDN$0.033 per share starting with its June dividend. The dividend was increased to CDN$0.038 per share for the dividend declared in August of 2021 and further increased to CDN$0.041 per share for the dividend declared in November of 2021.

During 2022, the Corporation began declaring dividends in U.S. dollars and declared the following quarterly dividends:

● Q1 2022 – US$0.033 per share, paid on March 15

● Q2 2022 – US$0.043 per share, paid on June 15

● Q3 2022 – US$0.050 per share, paid on September 15

● Q4 2022 – US$0.055 per share, paid on December 15

On February 23, 2023, Enerplus declared its first quarter 2023 dividend of US$0.055 per share, payable on March 15, 2023.

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 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.

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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 and state 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 (North Dakota, Pennsylvania and Colorado). The Corporation's oil and natural gas operations are regulated by a wide range of administrative agencies under statutory provisions of the states, 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 certain payments made to governments of all levels, including Indigenous groups 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 Indigenous groups in Canada and Native American tribes within the United States.

PRICING AND MARKETING OF CRUDE OIL AND NATURAL GAS

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, terms and conditions of service 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. In addition, exports of crude oil and natural gas liquids from the United States require a license from the Bureau of Industry and Security of the U.S. Department of Commerce, with certain export transactions generally approved and other transactions considered on a case-by-case basis to determine whether they are in the national interest.

Producers of natural gas 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. 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, terms and conditions of service 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

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natural gas prices continued to be volatile during 2022 in response to a variety of factors including, among others, supply and demand impacts due to the ongoing Ukraine and Russian conflict, lingering concerns over crude oil demand due to COVID, concerns over the potential impact of a global recession, as well as 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 the use of certain transmission or transportation facilities and the Corporation'sphysical 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 $1,496,035 per violation, per day, 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 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.

Royalties or similar payments payable on production from lands other than federal and state lands in the United States 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 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 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. However, in other instances, such royalties may be increased. For example, in November 2021, the U.S. Department of the Interior ("DOI") released a report with several recommendations on how to revise federal oil and gas leasing and permitting practices, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. The Inflation Reduction Act of 2022 (“IRA”), signed into law on August 16, 2022, responded to one of the report’s recommendations and increased onshore royalty rates to 16⅔%. Several of the report’s other recommendations, however, will require further Congressional action and Enerplus cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs and adversely impact the Corporation’s operations.

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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 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 Corporation's operations in North Dakota that are located on the Fort Berthold Indian Reservation (“FBIR”) involve allottee 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.

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, state and federal environmental laws and regulations in its operating areas in the U.S. These requirements provide for environmental protection and impose restrictions and prohibitions regarding disturbances and releases, or emissions of various regulated 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 restored 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 and natural resource 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 which are climate change-related, as well as public opposition and activism”.

In the United States, oil and gas operations are regulated at the federal, tribal, state and local 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 analogous state agencies whose programs have been granted primacy by the U.S. EPA. The U.S. EPA governs federal legislation, as amended from time to time, including the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act (other than oil and gas exploration and production 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.

Additional regulations affecting the Corporation's U.S. operations include: (i) the Federal Implementation Plan for Oil and Natural Gas Well Production Facilities, FBIR (Mandan, Hidatsa, and Arikara Nations) (the "MHA Nation"), in North Dakota

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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. In May 2020, the Office of the Solicitor of the DOI issued an opinion (the “Missouri River Opinion”) finding that the State of North Dakota, not the MHA Nation, was the legal owner of the minerals underlying the Missouri River. The MHA Nation filed actions in two federal courts seeking to overturn the May 2020 decision. In March 2021, the DOI withdrew the Missouri River Opinion and, only recently, on February 4, 2022, the DOI issued a new opinion on the matter, stating that the minerals beneath the Missouri River riverbed located on the FBIR belong to the MHA Nation and not the state of North Dakota. However, the state of North Dakota asserts that this decision is incorrect and is currently seeking to overturn a ruling that it not be allowed to intervene in litigation regarding the MHA Nation’s claims to mineral-related revenues. The Corporation cannot predict what effect this may ultimately have on its operations.

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 which are climate change-related, 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 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 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 of its operational areas.

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, with the BLM also seeking to determine the sufficiency of an operator’s methane waste minimization plan.

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 North Dakota Industrial Commission (“NDIC”) has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells. As of December 31, 2022, the Corporation was continuing to capture approximately 91% of its natural gas production in North Dakota. While it was satisfying the applicable gas capture percentage goals as of December 31, 2022, there is no assurance that Enerplus will remain in compliance in the future, or that such future satisfaction of such goals will not have a material adverse effect on its business and results of operations.

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.

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

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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. Additionally, on December 17, 2021, the Colorado Air Quality Control Commission adopted regulations aimed at curbing methane emissions from oil and gas operations to include setting methane emission limits per 1,000 barrels of oil equivalent produced, more frequent inspections, and limits on emissions during maintenance.

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, 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 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 regulatory oversight by the BCOGC. The abandonment of this property began in 2019 and the majority of work 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 governing statutory regime.

Alberta

In Alberta, the Alberta Energy Regulator (“AER") is the single regulator of oil and gas development in Alberta and oversees all aspects of the regulatory process, including related to 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. The AER operates in conjunction with Alberta Environment and Parks to ensure the province's environmental, social and economic targets are met. Alberta Environment and Parks is also responsible for climate change-related regulations such as the Alberta Technology Innovation and Emissions Reduction program. The Corporation is abandoning a property in 2023 and expects the program to last several years.

Climate change-related legislation

Globally, the shift to a low-carbon economy continues to shape ESG practices and business strategy, in particular with respect to climate change-related actions. Climate change-related legislation at the 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 change-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-related actions and provides the fundamental framework upon which the Securities and Exchange Commission’s (“SEC”) proposed rule on climate-related disclosures released in March 2022 is based upon. Four core recommendations have been presented which would apply to organizations across all sectors and jurisdictions. The four core areas of recommendation 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 continues to recognize the TCFD recommended guidelines and is working toward integrating fit for purpose disclosure from the guidelines into its ESG strategy. The TCFD Aligned Reporting Table in connection with Enerplus’ 2022 ESG Report is available at www.enerplus.com.

The United States was 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 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. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the 26th Conference of the Parties to the UN

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Framework Convention on Climate Change (“COP26”) in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, which is an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced in conjunction with the European Union and other partner countries that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future.

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 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 volatile organic compound (“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. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source standards of performance for methane and VOC emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance, which include leak detection using optical gas imaging and subsequent repair requirements, and reduction of emissions by 95% through capture and control systems. In November 2022, EPA released a supplemental methane proposal. Among other items, the proposal sets forth specific revisions strengthening the first nationwide emissions guidelines for states to limit methane emissions from existing oil and gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair, as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The EPA’s proposed rule would prohibit flaring at new sources (OOOO(b)) and later prohibit flaring at existing sources (OOOO(c)), except in certain limited circumstances. The proposal is currently subject to public comment and is expected to be finalized in 2023. Relatedly, the BLM has proposed new regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal leased land. The proposed rule would require payment of royalties on subject flared volumes and potential curtailment of production when flared volumes exceed certain rates. It is likely that both rules will be subject to legal challenges, though we cannot predict how this may affect implementation. To the extent finalized as proposed, these rules could increase our operating costs, limit our operations in certain areas, or otherwise adversely impact our business. Finally, the IRA imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector. Beginning in 2024, the methane emissions charge will begin at $900 per metric ton of leaked methane, rising to $1,200 in 2025, and $1,500 in 2026 and thereafter. Calculation of the fee is based on certain thresholds established in the IRA. 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 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 which are climate change-related, 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, including production targets, 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

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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.

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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.

Crude 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:  

● global energy supply and demand, production, and regulatory policies, including sanctions that may be placed on countries that supply energy to the global market

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

● the ability to export, considering government or political actions or orders, regulations, taxation, and market demand, crude oil and liquefied natural gas and NGLs from North America

● geopolitical uncertainty, including for example, the impact of the Ukraine and Russia conflict and European energy instability; the risk of international hostile actions, as well as actions in the United States or Canada that could disrupt trade or other relations

● sustained pandemics or epidemics, including the continuing effect of the COVID, pandemic, which may disrupt economies, whether local or global, and may impact supply, demand or commodity prices for crude oil, NGLs or natural gas

● global and domestic economic conditions, as well as currency fluctuations and inflation

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

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

● supply chain challenges and disruptions

● weather conditions

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

● the impact of world-wide energy conservation and decarbonization efforts, GHG reduction measures, the price and availability of alternative fuels and the impact of regulatory initiatives associated therewith

● 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 lower prices for some of their production due to regional constraints impacting their ability to transport and sell production in more favourably priced 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 ongoing volatility in commodity prices and in 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 capital spending available for the development of the Corporation's crude 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 when market conditions are less satisfactory for the Corporation. 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.

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Risks relating to the impact of the Ukraine and Russia conflict.

The existing conflict between Ukraine and Russia and the international response has, and may continue to have, potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Certain countries including Canada, the United States, Australia and certain European countries have imposed strict financial and trade sanctions against Russia, which may have continued far-reaching effects on the global economy, energy and commodity prices and food security and crop nutrient supply and prices. The short-, medium- and long-term implications of the conflict in Ukraine are difficult to predict with any degree of certainty at this time. Depending on the extent, duration, and severity of the conflict, it may have the effect of heightening many of the other risks described in this Annual Information Form and the MD&A, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of capital; and supply chains and cost-effective and timely transportation.

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 and/or free cash flow. Capital costs of completions, specifically the costs of steel, 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, other supply chain challenges, disruptions and adverse effects of inflation and rising interest rates, may result in higher than expected supply costs for the Corporation. Additionally, the Corporation has certain service contracts tied to inflationary measure benchmarks (such as the Consumer Price Index and WTI crude oil price), which could increase its operating costs should the benchmarks rise significantly.

The Corporation may be unable to compete successfully with other organizations in the oil and natural gas industry or obtain required supplies and 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 supply chain options the Corporation is not able to access, thereby limiting its ability to compete and potentially directly impacting its operational and financial results.

Service providers, including those the Corporation relies on, are also in a highly competitive environment that is impacted by worker availability, commodity prices and global supply inventories. Where worker availability is impacted by shortages, due to location or pandemic related issues, for example, 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/supplies, 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.

Increasing attention to ESG and sustainability matters may impact the Corporation's business.

Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability practices. These standards are evolving, and if the Corporation fails 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, the Corporation may suffer from reputational damage and the business, financial condition, and/or stock price could be materially and adversely affected.  Increasing attention to climate change and sustainability, increasing societal expectations on companies to address climate change-related targets, and potential consumer use of substitutes to fossil-fuel energy commodities may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on the Corporation's share price and access to capital markets. Increasing attention to climate change-related and sustainability targets and expected actions, for example, may result in

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demand shifts for hydrocarbon products and additional governmental investigations and private litigation against the Corporation.

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 the Corporation’s shares from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of the Corporation's operations by certain investors. Additionally, to the extent ESG matters negatively impact the Corporation’s reputation, it may not be able to compete as effectively to recruit or retain employees, which may adversely affect its operations.

The Corporation also makes certain disclosures regarding sustainability, publishing an ESG report that provides updates on its performance related to certain ESG topics and sets certain ESG goals. Many of its disclosures are necessarily based on estimates and assumptions that are inherently difficult to assess. Moreover, Enerplus may not be able to adequately identify ESG-related risks and opportunities and, further, may not be able to meet ESG targets in the manner, or on such a timeline as initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. While the Corporation may elect to seek out various additional voluntary ESG targets now or in the future, such targets are aspirational. Notwithstanding this, Enerplus may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but it cannot guarantee it will be able to implement such goals because of potential costs or technical or operational obstacles.

Additionally, public statements with respect to emissions reduction goals, environmental targets, or, more broadly, ESG-related goals, are becoming increasingly subject to heightened scrutiny from public and governmental authorities with respect to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. The Canadian securities regulators (the “CSA”) have been monitoring issuers’ disclosures relating to various ESG-related matters and have published a public guidance stating their concerns with certain practices involving unsupported claims that may constitute greenwashing. Certain non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, to include emission reduction goals or standards used, were misleading, false, or otherwise deceptive. As a result, the Corporation may face increased litigation risks which could, in turn, lead to further negative sentiment and diversion of investments. Enerplus could also face increasing costs to comply with increased regulatory focus and scrutiny.

Government policy and/or regulations and required regulatory approvals and compliance may adversely impact the Corporation's operations, including production targets, and result in increased operating and capital costs.

The oil and gas industry operates under federal, 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, gathering, transportation and 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 penalties, 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 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 may 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

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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 GHGs, 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.

Changes in laws or free trade agreements, including those affecting tax, royalties and other financial and trade matters, including exports, 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, prop0oed share buyback taxes 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.

The loss of members of the Corporation’s management or other 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 the Corporation's 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 Corporation's operation of oil and natural gas wells could subject it to environmental costs, claims and liabilities, including but not limited to those which are climate change-related, as well as public opposition and activism.

GENERAL

The oil and natural gas industry elicits concerns about climate change-related issues, as well as general public opposition to the industry. As a result, industry participants may be subject to increased public activism and, in particular, activist activity that may result in increased costs, delays or damage to facilities or operations. This may also result in negative impacts to industry supply chains, obstructing the availability of procured materials. In addition, extensive environmental regulation pursuant to local, federal and state laws and regulations in the United States, may result in legislative and regulatory changes that could have an adverse effect on the Corporation, including its ability to meet its production targets. Existing and future laws and regulations may also 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-related actions 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 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.

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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 global 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.

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 share repurchases and/or dividends to shareholders. Enerplus has estimated the present value of its future asset retirement obligations to be $114.7 million at December 31, 2022 (see its Financial Statements) the majority of which are expected to be incurred between 2023 and 2034 for Canada, and 2037 and 2052 for the United States.

The Corporation does not establish a separate reclamation fund for the purpose of funding its estimated future environmental and reclamation obligations; therefore, it cannot assure investors that it will be able to satisfy its future environmental and reclamation obligations. 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.

CLIMATE CHANGE-RELATED RISKS

As noted, public support for climate change-related 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. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, which is an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The impact of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, or other international conventions cannot be predicted at this time, and it is unclear what additional initiatives may be adopted or implemented that may have a negative impact on the Corporation’s financial condition.

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

Climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events (including but not limited to flooding, drought, winter storms, and wildfire) or changes in meteorological and hydrological patterns, which could adversely impact us or our contractors’ operations. Such physical risks may result in damage to our facilities or infrastructure we rely on to transport our products or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our products, such as to the extent

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warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our suppliers, which may adversely affect our operations. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured. However, the Corporation does not believe that its current operations expose it to physical risks in a manner which materially differs from those facing other North American onshore oil and gas producers.

Transition Risks - Regulatory and Policy

The global push to meet net zero emissions targets by 2050 increases the risk of potentially burdensome regulatory and/or policy changes from governments, some of which could have a direct, negative impact on the Corporation should they impede access or negatively impact our relationship with our stakeholders, service providers, lenders, insurers and the investment community. In addition, as a result of these regulations and policies, the Corporation could also be unable to obtain value for, or from, its oil and gas assets and reserves.

More specific concerns of the fossil fuels industry relate to GHG emissions, including methane, as well as water and land use. More stringent legislation or regulations in the United States, relative to other jurisdictions, including requirements to significantly reduce GHG emissions, water consumption, or setback requirements for facilities and wells, could result in increased costs and competitive disadvantages. For example, following the Trump Administration’s revision of certain emissions regulations to rescind certain requirements established in 2016, the U.S. Congress approved, and President Biden signed into law a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance, which include leak detection using optical gas imaging and subsequent repair requirements, and reduction of emissions by 95% through capture and control systems. In November 2022, EPA released a supplemental methane proposal which, among other items, set forth revisions strengthening the first nationwide emissions guidelines for states to limit methane emissions from existing oil and gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair, as well as equipment leaks, and the frequency of monitoring surveys and establishes a “super-emitter” response program to timely mitigate emissions events. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that it, alongside the November 2021 proposed rule, will be subject to legal challenges. President Biden has also made climate change a focus of his administration. In August 2022, the IRA passed into law. The IRA imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector. Beginning in 2024, the methane emissions charge will begin at $900 per metric tonne of leaked methane, rising to $1,200 in 2025, and $1,500 in 2026 and thereafter. President Biden and has also issued various executive orders calling for substantial climate change-related action, 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 change-related risks across agencies and economic sectors. Failure to comply with such regulations and laws could result in significant penalties being imposed. In addition, a potential increase in capital spending, operating expenses, abandonment and reclamation obligations, 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. See “Industry Conditions – Environmental Regulation – Climate change-related legislation”.

There is also a risk that financial institutions will adopt, or be pressured, or 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 change-related risks in the financial sector. Additionally, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net-zero emissions by 2050. The impact of these initiatives could require the adoption of new technologies, which could require a significant investment in capital and resources or result in additional costs if climate change-related targets are not achieved, therefore negatively impacting the Corporation's results and economics. The CSA and the SEC have separately released proposed rules that would establish a framework for the reporting of climate risks, targets, and metrics. Although the final form and substance of this rule and its requirements are not yet known, and the ultimate impact on the Corporation is uncertain, the proposed rule, if finalized, may result in increased compliance costs and increased costs of and restrictions on access to capital.

At COP26 many countries announced further expanded global climate goals and targets. Given the commitments made by Canada and the U.S., the Corporation may be subject to significant changes in government policy, resulting in reduced investment if it does not comply, or unplanned spending, which could impact its operations and financial condition. In addition, should policies put in place result in permanent, significant reductions in the demand for fossil fuels, commodity prices could be negatively impacted and result in asset impairment charges, or stranded assets. Although these policies could materially impact the Corporation, it is not possible for the Corporation to quantify or estimate such impact due to the current lack of clarity around policy changes and requirements currently, as well as the timing of the same.

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For a more detailed discussion on regulatory risks for the Corporation, please see "Supplemental Operational Information" and "Industry Conditions – Environmental Regulation".

Transition Risks – Reputational

The Corporation continues to develop its 2023 climate strategy, delivering a phased approach for key components during 2021 and 2022. This strategy will address climate change-related risks and opportunities for the Corporation. Examples of progress achieved in 2022 towards the goal include the implementation of solutions to improve emissions forecasting and integrating emissions into long-range planning. In addition, these initiatives have led to the initial development of a power strategy which, at this early stage incorporates electrification of certain facilities, the goal of which will be to further reduce emissions and improve the emission efficiencies of existing power sources when grid power is not available. Enerplus is participating in an electrification project in North Dakota in 2023 and approximately $10 million of the Corporation’s 2023 capital spending budget has been allocated to this initiative. The Corporation’s objective is to be a responsible operator—in the eyes of its shareholders, employees, contractors, regulators, lenders, communities and the general public, and this includes being responsive to climate change-related issues. However, despite its best intentions, activities undertaken directly by the Corporation or its employees in operating its business, or by others in industry, could adversely affect the Corporation’s reputation. For example, there has been an increase in activist activity in 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. A number of parties have sought to bring suit against certain oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. 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.

GHG Emissions and Targets

Among other sustainability goals, the Corporation has established a 2030 GHG emissions intensity reduction target of 35% for Scope 1 Emissions and Scope 2 Emissions (based on a 2021 baseline year). The Corporation's ability to lower GHG emissions on both an absolute basis and in respect of its 2030 emissions intensity reduction target is subject to numerous risks and uncertainties, and the Corporation’s actions taken to implement these objectives may also expose it to certain additional and/or heightened financial and operational risks. A reduction in GHG emissions intensity relies on, among other things, the Corporation’s ability to implement and improve energy efficiency at all facilities, future development and growth opportunities, development and deployment of new technologies and a focus on a reduction in flaring. In the event that the Corporation is unable to implement these strategies and technologies as planned without negatively impacting its expected operations or business plans, or in the event that such strategies or technologies do not perform as expected, the Corporation may be unable to meet its GHG emissions intensity reduction targets or goals on the current timelines, or at all. Moreover, given the evolving nature of GHG emissions accounting methodologies and climate science, we cannot guarantee that factors outside of the Corporation’s control could give rise to the need to restate or revise its emissions intensity reduction goals, cause them to be missed altogether, or limit the impact of success of achieving Enerplus’ goals.

While the Corporation may create and publish voluntary disclosures regarding ESG matters from time to time, certain statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, while we have announced, and may in the future announce,

various targets in an attempt to improve our ESG profile, we cannot guarantee that we will be able to meet any such targets or that such targets or offerings will have the intended results on our ESG profile, including, but not limited to, as a result of unforeseen costs, consequences, or technical difficulties associated with such targets.

In addition, achieving the Corporation's GHG emissions intensity reductions target and goals could require significant capital expenditures and resources, with the potential that the costs required to achieve such target and goals materially differ from the Corporation’s original estimates and expectations, which differences may be material. In addition, while the intent is to improve efficiency and reduce flaring, the shift in resources and focus towards GHG emissions reduction could have a negative impact on the Corporation’s operating results. The overall final cost of investing in and implementing a GHG emissions intensity reduction strategy and technologies in furtherance of such strategy, and the resultant change in the

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deployment of the Corporation's resources and focus, could have a material adverse effect on the Corporation’s business, financial condition and results of operations. While we may receive pressure from certain investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals or policies, we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

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 freshwater aquifers, the use of water in connection with completion operations, the ability of such water to be recycled, and induced seismicity associated with fracturing. U.S. federal and state 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, 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. In particular, President Biden issued an executive order suspending new leasing activities, but not operations under existing leases, for oil and gas exploration and production on non-Indian federal lands pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. Although the federal court for the Western District of Louisiana issued a preliminary injunction against the leasing pause in June 2021 and a permanent injunction in August 2022, in response to the executive order, the federal government and a coalition of environmental organizations are appealing this decision and the Department of Interior has issued a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. 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. 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 have a material adverse effect on the Corporation's results of operations and financial condition. 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, 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. See "Industry Conditions – Royalties and Incentives".

It is anticipated that U.S. federal and state regulatory frameworks to address concerns related to hydraulic fracturing will continue to emerge. While the Corporation is unable to predict the impact of any potential regulations upon its business, the implementation of new laws, regulations or permitting 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.

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. 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.

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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.

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.

Changes in U.S. administration may affect trade between countries.

There is uncertainty regarding U.S. support for existing treaty and trade relationships with other countries, 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 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 NYSE); and (e) general global economic conditions. All of these factors are outside of the Corporation’s 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 regulation of crude 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, 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.

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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 transport the Corporation’s product 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 paid 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. Should inadequate infrastructure exist, even from time to time, Enerplus could be subject to volume curtailments and low regional commodity prices at various times. 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 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 the Corporation’s 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 United States District Court for the District of Columbia ("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 shut down 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, but USACE has not pursued an enforcement action with regards to this alleged encroachment. In June of 2021, the District Court rejected a request to enjoin the operation of the pipeline due to the lack of an easement and DAPL continues to operate pending the outcome of the EIS process, which is ongoing. In September 2021, DAPL requested the United States Supreme Court ("SCOTUS") hear an appeal on the lower court’s decision to require the EIS and on the vacatur of the USACE permit. On February 22, 2022 SCOTUS denied certiorari, declining to hear the appeal. The Corporation is unable to determine the outcome or the impact on DAPL in the future. However, any future ruling or regulatory decision that restricts the availability of pipeline capacity in the Williston Basin may have a material adverse effect on the Corporation.

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

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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 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.

The third parties on whom the Corporation relies for gathering, transportation, and processing services are subject to complex federal, state, other laws that could adversely affect the Corporation’s operations.

The operations of the third parties on whom the Corporation relies for gathering, transportation and processing services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that the Corporation pays for services. Similarly, a failure to comply with such laws and regulations by the third parties could have a material adverse effect on the Corporation’s business and results of operations, which could have an adverse impact on the Corporation’s cash flows and financial condition.

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

Should production for the industry, or specifically for any of the Corporation’s products, be hampered by limited pipeline availability or capacity, government policy and regulations, or third-party business practices, or supply chain shortages, regional commodity prices may become volatile. 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, which may include decisions to curtail production or obtain adequate goods and services, and the ability to develop such properties as planned.

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.

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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, 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.

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 cash 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 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 allegedly inadequate governance), title, contractual and environmental matters (including those that are climate change-related). 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.

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

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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.

The Corporation, the use of digital technology, or its information assets and/or critical infrastructure may be subject to technopolitical or cyber security risks which could lead to financial losses or reputational issues.

The Corporation is subject to a variety of information technology and system risks as 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. 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. The adoption of emerging technologies, such as cloud computing, artificial intelligence and robotics, call for continued focus and investment to manage risks effectively. Although the Corporation actively manages its exposure to these risks, it may not be able to fully prevent events resulting 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; any damages sustained may not be adequately covered by the Corporation's current insurance coverage, or at all.

IT and cyber risks have increased since the beginning of the COVID pandemic and the Russia and Ukraine conflict, with cybercriminals taking advantage of remote working environments to increase malicious activities, creating more threats for cyberattacks. These include phishing emails, malware-embedded mobile apps that purport to track COVID infection rates, and targeting of vulnerabilities in remote access platforms. Although the Corporation has security measures and controls in place that are designed to mitigate these risks, the growing use of the digital space could increase technopolitical risks (example, by monitoring/intercepting phones and communications, or surveilling/locating persons of interest) further increasing the risk of a breach of its security measures, which could result in a loss of material and confidential information and/or have a negative impact on its reputation, result in a breach of privacy laws, and/or disrupt business activities. In addition, third party operators on whom we depend and the operations of our customers and business partners are also subject to such risks

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.

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 SLL Credit Facilities in order to carry out its operations and fulfill its obligations. Significant reductions to cash flow, significant increases in drawn amounts under the SLL Credit Facilities, or significant reductions to proved reserves may result in the Corporation breaching its debt covenants under the Credit Facilities. 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. Failure to comply with debt covenants, or negotiate relief, may result in the Corporation’s indebtedness under the Credit Facilities 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 and any replacement credit facility may not provide sufficient liquidity.

Although the Corporation believes that its existing Credit Facilities are sufficient, there can be no assurance that the current amount will continue to be available or will be adequate for the financial obligations of the Corporation, or that additional funds can be obtained as required or on terms which are economically advantageous to the Corporation. The amounts available under the SLL Credit Facilities may not be sufficient for future operations, or the Corporation may not be able to renew either or both of the SLL Credit Facilities, or obtain additional financing on attractive economic terms, if at all. Each of the SLL Credit Facilities is generally available on a three- to four-year term, extendable each year with a bullet payment required at the end of the period if the facility is not renewed. The Corporation renewed both of the SLL Credit Facilities in 2022, incorporating ESG-linked incentive pricing terms, and if the SPTs are not met, may result in higher future borrowing costs. The $365 million SLL Credit Facility currently expires on October 31, 2025; $50 million and $850 million of the $900 million SLL Credit Facility expire on October 31, 2025 and October 31, 2026, respectively. There can be no assurance that such a renewal will be available on favourable terms or that all of the current lenders under the facility will participate or renew at their current commitment levels. If this occurs, the Corporation may need to obtain alternate financing. Any failure

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of a member of the lending syndicate to fund its obligations under either of the SLL Credit Facilities or to renew its commitment in respect of any SLL 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 has priority over dividend payments by the Corporation to its shareholders. See “General Developments of the Business” and “Description of Capital Structure”.

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 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.

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

Under U.S. GAAP, the net capitalized cost of oil and gas properties, net of deferred income taxes, is limited to the present value of after-tax future net revenue from proved reserves, discounted at 10%, and based on the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer's fiscal quarter and annual fiscal periods. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

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 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 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”.

58    ENERPLUS 2022 ANNUAL INFORMATION FORM

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 will vary from the estimates summarized in this Annual Information Form, and those variations could be material. Estimates of reserves and resources are by necessity projections, and thus are inherently uncertain. The process of estimating reserves or resources requires interpretations and judgments on the part of petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Different engineers may make different estimates of 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 spending

● 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 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 crude oil and natural gas prices and higher costs increase the risk of write-downs of the Corporation’s crude oil and natural gas properties and deferred tax assets”. Write-downs may lead to the Corporation breaching its covenants under the Credit Facilities, 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”.

ENERPLUS 2022 ANNUAL INFORMATION FORM    59

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:  

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

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

● accounting delays or adjustments for prior periods

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

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

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

● blow-outs or other accidents

● title defects

● 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 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 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 status, 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.

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

Effective January 1, 2023, the Corporation changed its functional currency to U.S. dollars. However, transactions of some of the Corporation’s entities will continue to be affected by the exchange rate between the U.S. and Canadian dollar, as certain entities of the Corporation will continue to incur Canadian denominated payments including but not limited to, for example, general and administrative expenses and Canadian dollar cash dividend payments. The Corporation may from time to time use derivative instruments to manage a portion of its foreign exchange risk, as described in Note 16 to the Corporation's Financial Statements.

60    ENERPLUS 2022 ANNUAL INFORMATION FORM

Court rulings and regulatory regimes 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.

The Corporation is currently subject to regulation by the AER under the Licensee Liability Rating Program and the Large Facility Liability Management Program, which require licensee’s to provide the AER with a security deposit if deemed liabilities exceed deemed assets.

On July 30, 2020, the Government of Alberta announced a new and more holistic Liability Management Framework that would replace the current regime. Much of this Framework will be implemented through AER "Directive 088: Licensee Life-cycle Management" which came into force on December 1, 2021 and will replace the AER's current Licensee Liability Rating Program when it is fully implemented. The Liability Management Framework introduces several new programs and assessments relative to the life cycle of the Corporation's energy assets that are regulated by the AER, including the new licensee capability assessment, the Licensee Management Program, the Inventory Reduction Program (including mandatory annual closure spend targets or security requirements associated with inactive wells), security collection requirements and an expanded mandate for the OWA.

British Columbia has a similar liability management regime to the one formerly in place in Alberta and, like Alberta, is in the process of implementing changes to make its regime more robust. Although we do not expect such changes to have a material impact on our abandonment program, Enerplus cannot guarantee the impact on its abandonment plans at this time.

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 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 quarterly 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. Commencing in February 2022, cash dividends are declared in U.S. dollars and are converted to Canadian dollars and foreign denominated currencies, as applicable, at the spot exchange rate closer to the dividend payment date. Consequently, certain investors are subject to foreign exchange risk. To the extent that the U.S. 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:

ENERPLUS 2022 ANNUAL INFORMATION FORM    61

● 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)

● 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

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

● amounts required to fund capital spending 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 spending, 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 the Corporation. 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 the Corporation’s Code of Business Conduct at www.enerplus.com.

The ability of shareholders or investors outside of Canada 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.

62    ENERPLUS 2022 ANNUAL INFORMATION FORM

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 2022.

	TSX Trading			NYSE Trading
Month	High (CDN$)	Low (CDN$)	Volume	High (US$)	Low (US$)	Volume
January	15.36	12.96	32,041,767	12.26	10.21	10,624,156
February	16.23	14.28	30,624,056	12.81	11.23	9,980,680
March	18.74	14.62	49,503,220	14.59	11.42	15,919,222
April	17.64	14.79	27,706,882	14.07	11.58	10,203,939
May	19.62	14.68	35,132,510	15.50	11.25	12,245,294
June	23.29	16.20	46,930,330	18.58	12.46	14,164,542
July	18.09	14.48	23,339,014	14.11	11.00	10,472,246
August	21.43	15.48	24,243,590	16.48	12.04	10,115,813
September	21.30	17.02	23,820,340	16.19	12.39	11,327,292
October	24.11	20.12	20,566,435	17.80	14.73	10,081,414
November	25.72	22.95	23,191,292	19.23	16.76	10,351,183
December	25.41	21.90	18,104,534	18.92	16.00	8,580,183

ENERPLUS 2022 ANNUAL INFORMATION FORM    63

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.
Sherri A. Brillon(2)(4) Calgary, Alberta, Canada	October 2022	Corporate director. Prior thereto, Executive Vice-President and Chief Financial Officer of Encana Corporation from 2009 to 2019. ​
Judith D. Buie(2)(3)(5)(6) Houston, Texas, United States	January 2020	Corporate director and oil and gas industry advisor.
Karen E. Clarke-Whistler(3)(4)(5) 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(3)(4) Calgary, Alberta, Canada	November 2007	Corporate director. Mr. Hodgins held a part-time, non-officer position of Senior Advisor, Investment Banking at Canaccord Genuity Corp. from September 2018 to May 2022.
Mark A. Houser(2)(4)(5) Houston, Texas, United States	March 2022	Corporate director and founder and principal of Symphero Energy Solutions, LLC, an advisory services company in the oil and gas and renewable energy development markets. From 2015 to 2021, he served as Chief Executive Officer of University Lands, which manages the surface and mineral interests of 2.1 million acres of land in West Texas. ​
Susan M. MacKenzie(4)(5) Calgary, Alberta, Canada	July 2011	Corporate director.
Jeffrey W. Sheets(2)(4) Houston, Texas, United States	December 2017	Corporate director.
Sheldon B. Steeves(2)(5) 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 Jeffrey W. Sheets as Chair, Sherri A. Brillon, Judith D. Buie, Mark A. Houser and Sheldon B. Steeves.

3. The Corporate Governance & Nominating Committee is currently comprised of Robert B. Hodgins as Chair, Judith D. Buie and Karen E. Clarke-Whistler.

4. The Compensation & Human Resources Committee is currently comprised of Susan  M. MacKenzie as Chair, Sherri A. Brillon, Robert B. Hodgins, Karen E. Clarke-Whistler, Mark A. Houser and Jeffrey W. Sheets.

5. The Reserves, Safety & Social Responsibility Committee is currently comprised of Sheldon B. Steeves as Chair, Judith D. Buie, Karen E. Clarke-Whistler, Mark A. Houser and Susan  M. MacKenzie.

6. Ms. Buie was a director of Sundance Energy Australia Ltd., and subsequently Sundance Energy Inc. (“Sundance”) from February 2019 through April 2021, a US-based oil and gas company, which filed for voluntary Chapter 11 protection in the U.S. Bankruptcy Court for the Southern District of Texas on March 9, 2021. The filing was initiated with the support of Sundance’s lenders under a prepackaged plan of reorganization. Sundance emerged on April 23, 2021 from Chapter 11 bankruptcy as a privately held independent E&P based in Denver.

7. Ms. Foulkes was a director of Parallel Energy Trust (“Parallel”), a Canadian-based oil and gas trust, which commenced proceedings in the Court of Queen’s Bench of Alberta, under the Companies’ Creditors Arrangement Act (Canada) on November 9, 2015. 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.

64    ENERPLUS 2022 ANNUAL INFORMATION FORM

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.
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.
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 of the Corporation since June 2020. Prior thereto, Vice-President, U.S. Development & Geosciences of the Corporation.
Daniel J. Fitzgerald Calgary, Alberta, Canada	Vice-President, Business Development	Vice-President, Business Development of the Corporation.
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.
Pamela A. Ramotowski Calgary, Alberta, Canada	Vice-President, People & Culture	Vice-President, People & Culture since July 2022. Prior thereto, Vice President, Corporate Services at Steel Reef Infrastructure Corp., a North American based midstream company, from 2021 to 2022. Prior thereto, Vice President, Human Resources at Seven Generations Energy Ltd, a Canadian based E&P company, from 2018 to 2021.

COMMON SHARE OWNERSHIP

As of February 22, 2023, the directors and officers of the Corporation named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 1,010,176 Common Shares, representing approximately 0.47% of the outstanding Common Shares as of that date.

ENERPLUS 2022 ANNUAL INFORMATION FORM    65

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 E 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, among other things, the defendant companies have committed trespass and failed to pay royalties properly. 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, 2020 or in any proposed transaction that has materially affected or is reasonably expected to materially affect the Corporation.

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:

● Amended and Restated Agreement relating to the $365 million SLL Credit Facility (November 15, 2022);

● Amended and Restated Agreement relating to the $900 million SLL Credit Facility (November 15, 2022);

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

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

66    ENERPLUS 2022 ANNUAL INFORMATION FORM

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.

● the Articles of Amalgamation (January 2, 2013), and

● 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 the western United States, a summary of which is contained in this Annual Information Form. McDaniel also prepared estimates of contingent resources attributable to the Corporation's North Dakota properties, 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 is TSX Trust Company, at its principal offices in Calgary, Alberta and Toronto, Ontario. American Stock Transfer & Trust Company, LLC at its principal office 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 2023 annual meeting of shareholders. Furthermore, additional financial information relating to the Corporation is provided in the MD&A and the Financial Statements. 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.

ENERPLUS 2022 ANNUAL INFORMATION FORM    67

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 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, 2023. McDaniel has evaluated the Corporation's contingent resources associated with properties located in North Dakota, United States, using the average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2023.

The following sections and tables summarize, as at December 31, 2022, 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 spending, 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, 2023, and was utilized by NSAI and McDaniel in their 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 crude oil properties 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 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, 2023.

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

ENERPLUS 2022 ANNUAL INFORMATION FORM    A-1

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, 2022, 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.

Summary of Risked Oil and Gas

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2022

PROJECT MATURITY SUB-CLASS	Tight Oil		Natural Gas Liquids		Shale Gas		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)	(MBOE)
Development Pending	78,185	62,777	9,862	7,948	568,837	458,412	182,853	147,127

Risked Net Present Value of Future Net Revenue

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2022

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 US$ millions)
Development Pending	3,634.2	1,652.9	816.7	429.3	236.2

A-2    ENERPLUS 2022 ANNUAL INFORMATION FORM

DESCRIPTION OF PROPERTIES

Outlined below is a description of the Corporation's "best estimate" of economic contingent resources for its 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".

Crude Oil Properties

An evaluation of the Corporation's interests in the Bakken and Three Forks formations in the Corporation’s North Dakota properties was conducted independently by McDaniel, which has attributed an unrisked "best estimate" of 108.7 MMBOE (96.1 MMBOE risked) of economic contingent resources to these formations, effective as of December 31, 2022, a decrease of 32% from the estimate as of December 31, 2021. The decrease compared to 2021 was primarily the result of 51.2 MMBOE of unrisked contingent resources being converted to undeveloped reserves. 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 214.1 net future drilling locations over and above 366.5 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 $1,717.9 million between 2030 and 2035. 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 553.9 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 88% (80% for 1-mile lateral length horizontal wells and 90% for 2- and 3-mile lateral length horizontal wells) 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 $626.3 million. The Corporation has approximately 757.8 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 its North Dakota properties 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.

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 650.9 Bcf (520.7 Bcf risked) at December 31, 2022. The unrisked NPV (discounted at 10%) associated with these contingent resources is $238.0 million ($190.4 million risked). Approximately 59.4 Bcf of unrisked contingent resources were reclassified as reserves in 2022. An additional 91.1 Bcf of unrisked contingent resources (72.9 Bcf risked) were removed due to a technical review of offsetting development. The remaining contingent resources are economic based on the forecast price and cost assumptions used for the Corporation's year-end 2022 reserves evaluations. This estimate represents a non-reserve land utilization rate of 95% and average well ultimate recovery of approximately 15.5 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 development. It is also estimated that $380.5 million of capital will be required to develop these contingent resources with multifractured horizontal wells, and development will occur from 2027 to 2040.

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.

    ENERPLUS 2022 ANNUAL INFORMATION FORM    A-3

APPENDIX B

Appendix B - 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 the Corporation’s 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, which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the SEC, but does not necessarily include all of the disclosure required by the SEC disclosure requirements set forth in Subpart 1200 of Regulation S-K.

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 the Corporation’s reserves to be materially different from that presented.

The U.S. Rules require 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.

The reserves data disclosed are effective December 31, 2022. Concurrent to the evaluation of the Corporation’s Canadian NI 51-101 Standards reserves, McDaniel and NSAI prepared and reviewed estimates of the Corporation’s reserves under the U.S. Rules.

Proved reserves, proved developed reserves and proved undeveloped reserves are defined under the U.S. Rules. Proved crude oil and natural gas reserves are those quantities of crude oil and natural 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 reserves data presented in this Appendix B are a summary of evaluations, and as a result the tables may contain slightly different quantities than the evaluations themselves due to rounding. The Corporation also presents reserves estimates in accordance with National Instrument 51-101 “Standard of Disclosure for Oil and Gas Activities” which can differ significantly to those prepared under the U.S. Rules. Additionally, the columns and rows in the tables may not add due to rounding. See "Presentation of Oil and Gas Reserves, Contingent Resources, and Production Information – Notice to U.S. Readers" in this Annual Information Form.

Subsequent to December 31, 2022, 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 NGLs reserves are located in the United States, primarily in the states of Colorado, North Dakota and Pennsylvania. The Corporation’s net proved reserves summarized in the following table represent the Corporation’s lessor royalty, overriding royalty, and working interest share of reserves, after deduction of lessor royalties and overriding royalties as of December 31, 2022.

    ENERPLUS 2022 ANNUAL INFORMATION FORM    B-1

	United States		Canada		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, 2019	92,777	719,816	23,680	17,756	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	(39,543)	(263,700)	(5,115)	943	(44,658)	(262,757)	(88,451)
Improved recovery	-	-	-	-	-	-	-
Production	(12,690)	(65,672)	(2,382)	(4,239)	(15,072)	(69,911)	(26,724)
Proved Developed and Undeveloped
Reserves at December 31, 2020	42,475	407,056	16,182	14,461	58,657	421,517	128,910
Purchases of reserves in place	60,468	59,185	-	-	60,468	59,185	70,332
Sales of reserves in place	(3,419)	(7,838)	(118)	(1,514)	(3,537)	(9,352)	(5,095)
Discoveries and extensions	75,587	336,511	1,316	503	76,903	337,014	133,072
Revisions of previous estimates	14,984	153,647	4,024	4,960	19,009	158,607	45,443
Improved recovery	-	-	-	-	-	-	-
Production	(18,426)	(75,644)	(2,138)	(2,942)	(20,564)	(78,586)	(33,662)
Proved Developed and Undeveloped
Reserves at December 31, 2021	171,669	872,917	19,267	15,468	190,936	888,385	339,000
Purchases of reserves in place	255	143	-	-	255	143	279
Sales of reserves in place	(1,275)	(1,109)	(17,534)	(13,240)	(18,809)	(14,349)	(21,200)
Discoveries and extensions	17,984	122,762	-	-	17,984	122,762	38,444
Revisions of previous estimates	8,207	(34,877)	-	-	8,207	(34,877)	2,394
Improved recovery	-	-	-	-	-	-	-
Production	(20,787)	(82,368)	(1,733)	(2,228)	(22,520)	(84,596)	(36,619)
Proved Developed and Undeveloped
Reserves at December 31, 2022	176,053	877,468	-	-	176,053	877,468	322,298
Proved Developed Reserves
December 31, 2019	49,852	475,155	20,480	17,684	70,332	492,839	152,472
December 31, 2020	37,966	360,446	15,421	14,447	53,387	374,893	115,869
December 31, 2021	89,337	560,221	17,417	15,418	106,754	575,639	202,694
December 31, 2022	97,151	624,988	-	-	97,151	624,988	201,316
Proved Undeveloped Reserves
December 31, 2019	42,925	244,661	3,200	73	46,124	244,733	86,913
December 31, 2020	4,508	46,610	761	13	5,270	46,624	13,040
December 31, 2021	82,332	312,696	1,850	50	84,182	312,746	136,306
December 31, 2022	78,902	252,480	-	-	78,902	252,480	120,982

Purchases of reserves in place

In 2020, the Corporation acquired no additional working interest reserve volumes through purchases.

In 2021, the Corporation purchased 60,468 Mbbls of net proved crude oil and NGLs reserves and 59,185 MMcf of natural gas reserves through the acquisition of the Bruin and Dunn County assets within the Bakken/Three Forks formations in North Dakota.

In 2022, the Corporation purchased a number of small third party working interests in Enerplus operated wells in North Dakota, acquiring 255 Mbbls of net crude oil and NGLs reserves and 143 MMcf of natural gas reserves.

B-2    ENERPLUS 2022 ANNUAL INFORMATION FORM

Sales of reserves in place

In 2020, the Corporation did not sell working interests of any of its reserves in place.

In 2021, the Corporation divested 3,419 Mbbls of net proved crude oil and NGLs reserves and 7,838 MMcf of natural gas reserves from the sale of its crude oil property in the Sleeping Giant area in Montana.

In 2021, the Corporation also sold working interests in developed and undeveloped land in one crude oil property and six natural gas properties located in Alberta, accounting for 118 Mbbls of net proved crude oil and NGLs reserves and 1,514 MMcf of natural gas reserves.

In 2022, the Corporation divested 17,534 Mbbls of net proved crude oil and NGLs reserves and 13,240 MMcf of natural gas reserves from the sale of all Canadian properties with reserves volumes assigned, namely Ante Creek, Giltedge and Medicine Hat Glauconitic C Unit (in Alberta) and the Ratcliffe property(Saskatchewan).

In 2022, the Corporation divested 1,275 Mbbls of net proved oil and NGLs reserves and 1,109 MMcf of natural gas reserves in North Dakota through farming out interests in a pair of development units.

Discoveries and extensions

The Corporation added 1,655 Mbbls, 73,683 Mbbls and 17,984 Mbbls of net proved crude oil and NGLs reserves on its Bakken/Three Forks properties in 2020, 2021 and 2022, respectively. The Company added 15,299 MMcf, 271,393 MMcf and 109,250 MMcf of net proved natural gas reserves in 2020, 2021 and 2022, respectively, on its Marcellus natural gas property. These discoveries and extensions were primarily related to booking additional locations, as well as successful well development.

In 2020, there were no discoveries or extensions in Canadian crude oil or natural gas properties.

In 2021, Canadian discoveries and extensions accounted for an increase of 1,293 Mbbls of net proved crude oil reserves and 50 MMcf of natural gas reserves in the Giltedge and Medicine Hat Glauconitic C crude oil properties, and 23 Mbbls of net proved crude oil and NGLs reserves and 453 MMcf of net proved natural gas reserves in the Ferrier property, all located in Alberta.

In 2022, there were no discoveries or extensions in Canadian reserves properties as they were sold during the year.

Revisions of previous estimates

In 2020, negative revisions to United States crude oil reserves were primarily due to a decrease in the crude oil Constant Price, 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 reserves were also primarily due to a decrease in the natural gas Constant Price, which caused economic truncations of producing volumes and the removal of no longer economic undeveloped locations.

In 2021, positive revisions to United States crude oil reserves were primarily due to an increase in the crude oil Constant Price compared to 2020. Positive revisions to United States natural gas reserves were also primarily due to an increase in the natural gas Constant Price compared to 2020.

In 2022, positive revisions to United States crude oil reserves were primarily due to an increase in the crude oil Constant Price compared to 2021. Negative revisions to United States natural gas reserves were also primarily due to revised development plans and deletion of proved undeveloped locations in the Marcellus natural gas property.

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 crude oil Constant Price compared to 2019. Conversely, an increase in the Constant Price for Canadian natural gas compared to 2019 resulted in positive revisions to Canadian natural gas reserves.

In 2021, the positive revisions to Canadian crude oil reserves were primarily due to an increase in the crude oil Constant Price compared to 2020. Positive revisions to Canadian natural gas reserves were also primarily due to an increase in the natural gas Constant Price compared to 2020.

In 2022, there were no revisions of previous estimates in Canadian reserves properties as they were sold during the year.

Improved Recovery

There were no improved recovery revisions for the years 2020, 2021 and 2022.

    ENERPLUS 2022 ANNUAL INFORMATION FORM    B-3

B. CAPITALIZED COSTS RELATED TO CRUDE OIL AND GAS PRODUCING ACTIVITIES

The capitalized costs and related accumulated depreciation and depletion, including impairments, relating to the Corporation’s crude oil and natural gas exploration, development and producing activities are as follows:

	2022		2021		2020
	(in US$ thousands)
Capitalized costs(1)	$	7,214,993	$	13,075,987	$	11,966,258
Less accumulated depletion, depreciation and impairment		(5,892,090)		(11,822,482)		(11,513,956)
Net capitalized costs	$	1,322,903	$	1,253,505	$	452,302

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 natural 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 natural 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 natural 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, 2022
	United States		Canada		Total
	(in US$ thousands)
Acquisition of properties:
Proved	$	21,290	$	1,225	$	22,515
Unproved		-		-		-
Exploration costs		1,493		244		1,737
Development costs		429,306		60,453		489,759
	$	452,089	$	61,922	$	514,011

	For the Year Ended December 31, 2021
	United States		Canada		Total
	(in US$ thousands)
Acquisition of properties:
Proved	$	832,808	$	2,339	$	835,147
Unproved		-		-		-
Exploration costs		861		73		934
Development costs		331,341		25,528		356,869
	$	1,165,010	$	27,940	$	1,192,950

	For the Year Ended December 31, 2020
	United States		Canada		Total
	(in US$ thousands)
Acquisition of properties:
Proved	$	-	$	225	$	225
Unproved		5,522		1,744		7,266
Exploration costs		480		98		578
Development costs		200,986		18,136		219,122
	$	206,988	$	20,203	$	227,191

B-4    ENERPLUS 2022 ANNUAL INFORMATION FORM

D. RESULTS OF OPERATIONS FOR CRUDE OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to the Corporation’s crude oil and natural gas producing activities for the years ended December 31, 2022, 2021 and 2020:

	For the Year Ended December 31, 2022
	United States		Canada		Total
	(in US$ thousands)
Revenue
Sales(1)	$	2,205,876	$	147,499	$	2,353,374
Deduct(2)
Production costs(3)		639,279		48,075		687,354
Depletion, depreciation and accretion (“DD&A”)		286,438		22,929		309,367
Impairment		-		-		-
Current and deferred income tax provision (recovery)		246,006		47,290		293,296
Results of operations for oil and gas producing activities	$	1,034,153	$	29,204	$	1,063,357
DD&A per net BOE unit of production	$	8.30	$	10.90	$	8.45

	For the Year Ended December 31, 2021
	United States		Canada		Total
	(in US$ thousands)
Revenue
Sales(1)	$	1,355,253	$	127,322	$	1,482,575
Deduct(2)
Production costs(3)		472,849		49,846		522,695
Depletion, depreciation and accretion (“DD&A”)		246,949		24,387		271,336
Impairment		-		3,420		3,420
Current and deferred income tax provision (recovery)		151,620		(50,176)		101,444
Results of operations for oil and gas producing activities	$	483,835	$	99,845	$	583,680
DD&A per net BOE unit of production	$	7.96	$	9.28	$	8.06

	For the Year Ended December 31, 2020
	United States		Canada		Total
	(in US$ thousands)
Revenue
Sales(1)	$	480,822	$	72,917	$	553,739
Deduct(2)
Production costs(3)		284,071		49,124		333,195
Depletion, depreciation and accretion (“DD&A”)		183,226		34,892		218,118
Impairment		799,997		100,943		900,940
Current and deferred income tax provision (recovery)		(178,551)		(20,425)		(198,976)
Results of operations for oil and gas producing activities	$	(607,921)	$	(91,617)	$	(699,538)
DD&A per net BOE unit of production	$	7.75	$	11.30	$	8.16

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.

    ENERPLUS 2022 ANNUAL INFORMATION FORM    B-5

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 the Corporation’s crude oil and natural gas reserves:

	As at December 31, 2022
	United States			Canada	Total
	(in $US millions)
Future cash inflows	$	17,173	$	-	$17,173
Future production costs		4,010		-	4,010
Future development and asset retirement costs		1,705		-	1,705
Future income tax expenses		2,523		-	2,523
Future net cash flows	$	8,935	$	-	$ 8,935
Deduction: 10% annual discount factor		3,406		-	3,406
Standardized measure of discounted future net cash flows	$	5,529	$	-	$ 5,529

	As at December 31, 2021
	United States			Canada	Total
	(in $US millions)
Future cash inflows	$	10,499	$	1,023	$11,522
Future production costs		3,293		425	3,718
Future development and asset retirement costs		1,486		140	1,626
Future income tax expenses		1,064		-	1,064
Future net cash flows	$	4,655	$	459	$ 5,114
Deduction: 10% annual discount factor		1,552		149	1,701
Standardized measure of discounted future net cash flows	$	3,103	$	309	$ 3,413

	As at December 31, 2020
	United States			Canada	Total
	(in $US millions)
Future cash inflows	$	1,375	$	427	$ 1,802
Future production costs		832		256	1,088
Future development and asset retirement costs		174		199	373
Future income tax expenses		-		-	-
Future net cash flows	$	370	$	(29)	$ 341
Deduction: 10% annual discount factor		41		(69)	(27)
Standardized measure of discounted future net cash flows	$	329	$	40	$ 368

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

	2022		2021		2020
	(in $US millions)
Beginning of year	$	3,413	$	368	$	1,476
Sales of oil and natural gas produced, net of production costs		(1,666)		(960)		(221)
Net changes in sales prices and production costs		4,845		2,347		(2,030)
Changes in previously estimated development costs incurred during the period		410		302		217
Changes in estimated future development costs		(548)		(1,278)		557
Extension, discoveries and improved recovery, net of related costs		981		2,285		30
Purchase of reserves in place		1		1,214		-
Sales of reserves in place		(229)		(12)		-
Net change resulting from revisions in previous quantity estimates		(1,062)		(251)		122
Accretion of discount		300		26		136
Net change in income taxes		(917)		(630)		82
Other significant factors (Exchange rate)		-		3		(2)
End of year	$	5,529	$	3,413	$	368

B-6    ENERPLUS 2022 ANNUAL INFORMATION FORM

ADDITIONAL RESERVES INFORMATION CALCULATED IN ACCORDANCE WITH U.S. RULES

G. NET RESERVES PROVED RESERVES SUMMARY

The following table sets forth a summary of the Corporation’s total proved reserves based on volumes that are calculated in accordance to U.S. Rules, using net reserves and Constant Prices and Costs, and presented by product types that the Corporation used to report under the Canadian Standards.

	Tight Oil (Mbbls)	Total Crude Oil (Mbbls)	Natural Gas Liquids (Mbbls)	Shale Gas (MMcf)	Total (MBOE)
Net
Proved developed producing	78,342	78,342	15,993	621,563	197,928
Proved developed non-producing	2,468	2,468	348	3,425	3,387
Proved undeveloped	68,144	68,144	10,758	252,480	120,982
Total Proved	148,953	148,953	27,100	877,468	322,298

H. NET PROVED RESERVES RECONCILIATION

The following table sets forth a summary of the Corporation’s total proved reserves based on volumes that are calculated in accordance to U.S. Rules, using net reserves and Constant Prices and Costs, and presented by product types that the Corporation used to report under the Canadian Standards.

7
	Light & Medium Oil (Mbbls)	Heavy Oil (Mbbls)	Tight Oil (Mbbls)	Total Crude Oil (Mbbls)	Natural Gas Liquids (Mbbls)	Conventional Natural Gas (MMcf)	Shale Gas (MMcf)	Total Natural Gas (MMcf)	Total (MBOE)
Proved Reserves at Dec. 31, 2021	5,213	13,464	144,697	163,374	27,561	15,117	873,268	888,385	339,000
Purchases of reserves in place	-	-	231	231	24	-	143	143	278
Sales of reserves in place	(4,502)	(12,531)	(1,148)	(18,181)	(628)	(12,955)	(1,395)	(14,349)	(21,200)
Discoveries and extensions	-	-	15,554	15,554	2,430	-	122,762	122,762	38,444
Revisions of previous estimates	-	-	6,961	6,961	1,246	-	(34,876)	(34,876)	2,394
Improved recovery	-	-	-	-	-	-	-	-	-
Production	(712)	(933)	(17,342)	(18,986)	(3,534)	(2,162)	(82,433)	(84,596)	(36,619)
Proved Reserves at Dec. 31, 2022	-	-	148,953	148,953	27,100	-	877,468	877,468	322,298

I. FUTURE DEVELOPMENT COSTS

The following table sets forth a summary of the amount of development costs deducted in the estimation of the net present value of future cash flows associated with the Corporation’s proved reserves.

The following table sets forth a summary of the amount of development costs deducted in the estimation of the net present value of future cash flows associated with the Corporation’s proved reserves.the
	U.S. Standards(1)
Future Development Costs	Proved Reserves
(US$ millions)
2023	484
2024	344
2025	457
2026	236
2027	1
2028	-
Remainder	-
Total FDC Undiscounted	1,523
Total FDC Discounted at 10%	1,297

(1) FDC under U.S. Standards are not inflated.

    ENERPLUS 2022 ANNUAL INFORMATION FORM    B-7

APPENDIX C‌

Appendix C – 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, 2022. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2022, 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, 2022, 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, 2022, 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 US$ thousands)
or Auditor	Report	Reserves	Audited	Evaluated		Reviewed		Total
McDaniel & Associates Consultants Ltd.	December 31, 2022	North Dakota & Colorado, USA	-	$	6,048,905.3	$	-	$	6,048,905.3
Netherland, Sewell & Associates, Inc.	December 31, 2022	Pennsylvania, USA	-	$	949,061.9	$	-	$	949,061.9
		Pennsylvania, USA
TOTALS				$	6,997,967.3	$	-	$	6,997,967.3

● 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:

    ENERPLUS 2022 ANNUAL INFORMATION FORM    C-1

	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 US$ thousands)
Classification	or Auditor	Report	Reserves	(MMBOE)	Audited			Evaluated		Total
Development Pending Contingent Resources (2C)	McDaniel & Associates Consultants Ltd.	December 31, 2022	North Dakota, USA	96.1	$	-	$	626,327.00	$		626,327.0
Development Pending Contingent Resources (2C)	Netherland, Sewell & Associates, Inc.	December 31, 2022	Pennsylvania, USA	86.8	$	-	$	190,371.3	$		190,371.3

● 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.

● Executed as to our report referred to above:

MCDANIEL & ASSOCIATES CONSULTANTS LTD.	NETHERLAND, SEWELL & ASSOCIATES, INC.
"signed by B. Hamm"	"signed by Richard B. Talley"
B. Hamm, P.Eng.	Richard B. Talley, Jr., P.E.
President & CEO	Chief Executive Officer
Calgary, Alberta, Canada	Texas Registered Engineering Firm F-2699
	Dallas, Texas, USA
February 22, 2023	February 22, 2023

C-2    ENERPLUS 2022 ANNUAL INFORMATION FORM

APPENDIX D

Appendix D – 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 C to this Annual Information Form.

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

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

2. 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

3. 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:

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

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

● 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"	"Wade D. Hutchings"
Ian C. Dundas	Wade D. Hutchings
President & Chief Executive Officer	Senior Vice-President & Chief Operating Officer
"Hilary Foulkes"	"Sheldon B. Steeves"
Hilary Foulkes	Sheldon B. Steeves
Director	Director
February 23, 2023

   ENERPLUS 2022 ANNUAL INFORMATION FORM    D-1

APPENDIX E

Appendix E – Audit & Risk Management Committee Disclosure Pursuant to National Instrument 52-110

A.THE AUDIT & RISK MANAGEMENT COMMITTEE'S CHARTER

The charter of the Audit & Risk Management Committee (the "Committee") of the board of directors of the Corporation is included in this Appendix E.

B.COMPOSITION OF THE AUDIT & RISK MANAGEMENT COMMITTEE

The current members of the Committee are Jeffrey W. Sheets (Committee Chair), Sherri A. Brillon, Judith D. Buie, Mark A. Houser and Sheldon B. Steeves. 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
Jeffrey W. Sheets (B.Sc. (Chemical Engineering), MBA (Finance)) (Director since December 2017) Other Public Directorships ·     Schlumberger Limited (global oilfield services & equipment) ·     Westlake Chemical Corporation (chemicals & plastics sales & 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.
Sherri A. Brillon (B. Arts (Economics)) (Director since October 2022)	Ms. Brillon has over 35 years of experience in the oil and gas industry. From 1985 to 2019, Ms. Brillon held various positions of increasing responsibility at Encana Corporation (now known as Ovintiv Inc.) which included serving as Executive Vice-President and Chief Financial Officer for a decade prior to her retirement in 2019. At Encana, Ms. Brillon was responsible for directing the financial operations of the organization as well as implementing Encana's business strategy through multiple strategic transactions. Ms. Brillon currently serves on the board of directors for Delek Logistics Partners LP and is a past director of the Canadian Chamber of Commerce, Alberta Energy Regulator, Tim Hortons Inc., and PrairieSky Royalty Ltd. She attended the University of Calgary, where she graduated with a Bachelor of Arts degree in economics.

ENERPLUS 2022 ANNUAL INFORMATION FORM    E-1

Name (Director Since)		Principal Occupation and Biography
Judith D. Buie (B.Sc. (Chemical Engineering)) (Director since January 2020)	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 worked 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 currently serves on the board of directors of a private oil and gas company. She also serves as an oil and gas industry advisor. Ms. Buie received a Bachelor of Science in Chemical Engineering from Texas A&M University.
Mark A. Houser (B. Sc. (Petroleum Engineering), MBA (Director since March 2022)	Mr. Houser is the founder and principal of Symphero Energy Solutions, LLC, an advisory services company in the oil and gas and renewable energy development markets. From 2015 to 2021, he served as Chief Executive Officer of University Lands, which manages the surface and mineral interests of 2.1 million acres of land in West Texas. Prior to that, he held multiple executive roles for Enervest, Ltd. from 1999 to 2015, including Executive Vice President and Chief Operating Officer. Mr. Houser served in a variety of executive and senior management roles with Occidental Petroleum & Canadian Occidental Petroleum, Ltd. from 1989 to 1999.  He began his career in 1984 with Kerr-McGee Corporation in various production and reservoir engineering positions. Mr. Houser currently serves on the Investment Committee for a privately held oil and gas investment firm.  He also serves on the Board of Directors of the Houston Methodist Hospital System and is a member of the Board of Stewards of Chapelwood United Methodist Church. He received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University, College Station Texas and an MBA from Southern Methodist University.
Sheldon B. Steeves (B. Sc. (Geology) (Director since June 2012) Other Public Directorships ·     NuVista Energy Ltd. (oil & gas company) ·     PrairieSky Royalty Ltd. (oil & gas royalty)	Mr. Steeves has over 40 years of experience in the North American oil and gas industry and is currently a corporate director. From January 2001 until April 2012, Mr. Steeves was Chairman and Chief Executive Officer of Echoex Ltd., a junior private oil and gas company focused on greenfield organic growth in Western Canada. Mr. Steeves spent over 15 years at Renaissance Energy Ltd. where he was appointed Chief Operating Officer in 1997. He holds a Bachelor of Science in Geology from the University of Calgary.

D.PRE-APPROVAL POLICIES AND PROCEDURES

The Committee has implemented a policy restricting the services that may be provided by the Corporation's auditors and the fees paid to the Corporation's auditors. Prior to the engagement of the Corporation's auditors to perform both audit and non-audit services, the Committee pre-approves the provision of the services. In making their determination regarding non-audit services, the Committee considers the compliance with the policy and the provision of non-audit services in the context of avoiding impact on auditor independence. All audit and non-audit fees paid to KPMG in 2022 and 2021 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.

E-2    ENERPLUS 2022 ANNUAL INFORMATION FORM

E.EXTERNAL AUDITOR SERVICE FEES

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:

		2022		2021
		(in US$ thousands)
Audit fees(1)	$	835.9	$	897.6
Audit-related fees(2)		-		-
Tax fees(3)		377.1		190.0
All other fees(4)		-		-
TOTAL	$	1,213.0	$	1,087.6

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”, “Audit-related fees” and “Tax fees”.

ENERPLUS 2022 ANNUAL INFORMATION FORM    E-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.  

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

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 that person’s 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. The presence in person, virtually, 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. 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 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

2. Review and approve the Corporation’s external auditors’ annual engagement letter, including the proposed fees contained therein

E-4    ENERPLUS 2022 ANNUAL INFORMATION FORM

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 US generally accepted auditing standards

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

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

ENERPLUS 2022 ANNUAL INFORMATION FORM    E-5

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.          Oversight over management’s process for conducting the Corporation’s key risk assessment and approve the policies to monitor, mitigate and report such business risks.

18. Assess the effectiveness of management’s protocols and strategies regarding cyber and business critical information security.

E-6    ENERPLUS 2022 ANNUAL INFORMATION FORM

Other Matters

19.        Review of appointment or dismissal of senior financial executives

20.        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

21.        Review the disclosure made in the Annual Information Form, 40-F and the Information Circular regarding the Committee

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

23.        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

24.        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

25.        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 2022 ANNUAL INFORMATION FORM    E-7

Enerplus Corporation

The Dome TowerUS Bank Tower

Ste 3000, 333 - 7th Avenue S.W.Ste 2200, 950 – 17^th Street
Calgary, Alberta, CanadaDenver, Colorado, United States
T2P 2Z180202-2805
Telephone: 403.298.2200Telephone: 720-279-5500

Fax: 403.298.2211Fax: 720-279-5550
investorrelations@enerplus.com

www.enerplus.com

EX-99.2

        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, 2022, 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, 2022, 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, 2022.

/s/ Ian C. Dundas	/s/ Jodine J. Jenson Labrie
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer

Calgary, Alberta

February 23, 2023

ENERPLUS 2022 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 and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2022, 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, 2022, 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, 2022 and 2021, the related consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity, and cash flow for each of the years in the three-year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements), and our report dated February 23, 2023 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 23, 2023

2             ENERPLUS 2022 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 23, 2023. 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 23, 2023

ENERPLUS 2022 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 and subsidiaries (the Company) as of December 31, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022 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, 2022, 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 23, 2023 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 Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

4             ENERPLUS 2022 FINANCIAL SUMMARY

Impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to United States of America (“US”) 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. Under such method, capitalized costs for the US oil and gas properties are depleted over the estimated proved oil and gas reserves (“country proved reserves”). For the year ended December 31, 2022, the Company recorded depletion, depreciation and accretion expense of $309.4 million, a portion of which related to depletion expense on the US oil and gas properties. Additionally, as discussed in Notes 2(d) and 6 to the consolidated financial statements, the Company is required to perform a quarterly ceiling test calculation on a country-by-country basis. For the year ended December 31, 2022, the Company recorded no ceiling test impairments related to the US oil and gas properties. 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 assumptions related to forecasted production and forecasted operating and capital costs. 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 impact of estimated country proved reserves on the calculations of depletion expense and the ceiling test related to US oil and gas properties as a critical audit matter. Changes in reserve assumptions related to forecasted production and forecasted operating and capital costs could have had a significant impact on the calculations of depletion expense and the ceiling test. A high degree of auditor judgment was required in evaluating the country proved reserves, and assumptions related to forecasted production and forecasted operating and capital costs, 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, and

● the estimation of the country proved reserves and the assumptions related to forecasted production and forecasted operating and capital costs.

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 2022 actual production and operating 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 and capital cost assumptions used in the country proved reserves by comparing them to historical results.

/s/ KPMG LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 2017

Calgary, Canada

February 23, 2023

ENERPLUS 2022 FINANCIAL SUMMARY             5

       STATEMENTS

Consolidated Balance Sheets

(US$ thousands)	Note	December 31, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents		$	38,000	$	61,348
Accounts receivable	4		276,590		227,988
Other current assets	3		56,552		10,956
Derivative financial assets	16		36,542		5,668
			407,684		305,960
Property, plant and equipment:
Crude oil and natural gas properties (full cost method)	5, 6		1,322,904		1,253,505
Other capital assets	5		10,685		13,887
Property, plant and equipment			1,333,589		1,267,392
Other long-term assets	3		21,154		9,756
Right-of-use assets	10		20,556		26,118
Deferred income tax asset	14		154,998		380,858
Total Assets		$	1,937,981	$	1,990,084
Liabilities
Current liabilities
Accounts payable	7	$	398,482	$	367,008
Current portion of long-term debt	8		80,600		100,600
Derivative financial liabilities	16		10,421		143,200
Current portion of lease liabilities	10		13,664		10,618
			503,167		621,426
Long-term debt	8		178,916		601,171
Asset retirement obligation	9		114,662		132,814
Derivative financial liabilities	16		—		7,098
Lease liabilities	10		9,262		18,265
Deferred income tax liability	14		55,361		—
Total Liabilities			861,368		1,380,774
Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: December 31, 2022 – 217 million shares
December 31, 2021 – 244 million shares	15		2,837,329		3,094,061
Paid-in capital			50,457		50,881
Accumulated deficit			(1,509,832)		(2,238,325)
Accumulated other comprehensive loss			(301,341)		(297,307)
			1,076,613		609,310
Total Liabilities & Shareholders' Equity		$	1,937,981	$	1,990,084
Commitments and Contingencies	17
Subsequent Events	3, 15

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/ Jeffrey Sheets
Director	Director

6             ENERPLUS 2022 FINANCIAL SUMMARY            

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

For the year ended December 31 (US$ thousands)	Note	2022		2021		2020
Revenues
Crude oil and natural gas sales	11	$	2,353,374	$	1,482,575	$	553,739
Commodity derivative instruments gain/(loss)	16		(197,686)		(274,432)		75,742
			2,155,688		1,208,143		629,481
Expenses
Operating			365,701		292,433		197,097
Transportation			154,658		128,309		98,681
Production taxes			166,995		101,953		37,417
General and administrative	12		69,954		56,807		43,097
Depletion, depreciation and accretion			309,367		271,336		218,118
Asset impairment	6		—		3,420		751,723
Goodwill impairment	6		—		—		149,217
Interest			24,553		27,395		20,737
Foreign exchange (gain)/loss	13		10,159		(6,908)		1,232
Gain on divestment of assets	3		(151,937)		—		—
Transaction costs and other expense/(income)	3, 9		(1,360)		(2,487)		4,489
			948,090		872,258		1,521,808
Income/(Loss) Before Taxes			1,207,598		335,885		(892,327)
Current income tax expense/(recovery)	14		28,063		2,689		(10,716)
Deferred income tax expense/(recovery)	14		265,233		98,755		(188,260)
Net Income/(Loss)		$	914,302	$	234,441	$	(693,351)
Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation			22,507		(6,893)		(2,169)
Foreign exchange gain/(loss) on net investment hedge, net of tax	16		(26,541)		4,097		1,780
Total Comprehensive Income/(Loss)		$	910,268	$	231,645	$	(693,740)
Net Income/(Loss) per Share
Basic	15	$	3.91	$	0.93	$	(3.12)
Diluted	15	$	3.77	$	0.90	$	(3.12)

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

ENERPLUS 2022 FINANCIAL SUMMARY             7

Consolidated Statements of Changes in Shareholders’ Equity

For the year ended December 31 (US$ thousands)	2022		2021		2020
Share Capital
Balance, beginning of year	$	3,094,061	$	3,113,829	$	3,106,875
Purchase of common shares under Normal Course Issuer Bid		(266,694)		(128,686)		(3,582)
Share-based compensation – treasury settled		9,962		9,402		10,694
Issue of shares (net of tax effected issue costs)		—		99,516		—
Cancellation of predecessor shares		—		—		(158)
Balance, end of year	$	2,837,329	$	3,094,061	$	3,113,829
Paid-in Capital
Balance, beginning of year	$	50,881	$	49,382	$	56,439
Share-based compensation – tax withholdings settled in cash		(13,386)		(3,551)		(5,567)
Share-based compensation – treasury settled		(9,962)		(9,402)		(10,694)
Share-based compensation – non-cash		22,924		14,452		9,204
Balance, end of year	$	50,457	$	50,881	$	49,382
Accumulated Deficit
Balance, beginning of year	$	(2,238,325)	$	(2,447,735)	$	(1,736,355)
Purchase of common shares under Normal Course Issuer Bid		(144,212)		5,504		1,775
Cancellation of predecessor shares		—		—		158
Net income/(loss)		914,302		234,441		(693,351)
Dividends declared(1)		(41,597)		(30,535)		(19,962)
Balance, end of year	$	(1,509,832)	$	(2,238,325)	$	(2,447,735)
Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of year	$	(297,307)	$	(294,511)	$	(294,122)
Unrealized gain/(loss) on foreign currency translation		22,507		(6,893)		(2,169)
Foreign exchange gain/(loss) on net investment hedge, net of tax		(26,541)		4,097		1,780
Balance, end of year	$	(301,341)	$	(297,307)	$	(294,511)
Total Shareholders’ Equity	$	1,076,613	$	609,310	$	420,965

(1) For the year ended December 31, 2022, dividends declared were $0.181 per share (2021 – $0.121 per share; 2020 – $0.090 per share).

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

8             ENERPLUS 2022 FINANCIAL SUMMARY

Consolidated Statements of Cash Flows

For the year ended December 31 (US$ thousands)	Note	2022		2021		2020
Operating Activities
Net income/(loss)		$	914,302	$	234,441	$	(693,351)
Non-cash items add/(deduct):
Depletion, depreciation and accretion			309,367		271,336		218,118
Asset impairment	6		—		3,420		751,723
Goodwill impairment	6		—		—		149,217
Changes in fair value of derivative instruments	16		(150,526)		109,536		18,074
Deferred income tax expense/(recovery)	14		265,233		98,755		(188,260)
Foreign exchange (gain)/loss on debt and working capital	13		11,217		(8,055)		1,363
Share-based compensation and general and administrative	12,15		22,529		13,424		9,508
Other expense/(income)	3, 9		(4,137)		(4,594)		—
Amortization of debt issuance costs	8		1,476		1,093		—
Translation of U.S. dollar cash held in parent company	13		(937)		(2,330)		(902)
Gain on divestment of assets	3		(151,937)		—		—
Other expense/(income) reclassified to Investing Activities	3,19		13,702		(4,593)		—
Asset retirement obligation settlements	9		(17,401)		(12,951)		(13,275)
Changes in non-cash operating working capital	19		(39,506)		(94,643)		83,669
Cash flow from/(used in) operating activities			1,173,382		604,839		335,884
Financing Activities
Drawings from/(repayment of) bank credit facilities	8		(340,650)		400,000		—
Repayment of senior notes	8		(100,600)		(81,600)		(81,600)
Debt issuance costs	8		(1,005)		(4,621)		—
Purchase of common shares under Normal Course Issuer Bid	15		(410,906)		(123,182)		(1,807)
Proceeds from the issuance of shares	15		—		98,339		—
Share-based compensation – tax withholdings settled in cash	15		(13,386)		(3,551)		(5,567)
Dividends	15,19		(41,597)		(32,284)		(19,897)
Cash flow from/(used in) financing activities			(908,144)		253,101		(108,871)
Investing Activities
Capital and office expenditures	19		(429,873)		(271,131)		(248,990)
Bruin acquisition	3		—		(420,249)		—
Dunn County acquisition	3		—		(305,076)		—
Canadian divestments	3,19		158,033		—		—
Property and land acquisitions	5		(22,515)		(9,846)		(7,491)
Property and land divestments	3, 5		18,385		108,193		4,456
Other (expense)/income	3,19		(13,702)		4,593		—
Cash flow from/(used in) investing activities			(289,672)		(893,516)		(252,025)
Effect of exchange rate changes on cash and cash equivalents			1,086		6,979		(1,786)
Change in cash and cash equivalents			(23,348)		(28,597)		(26,798)
Cash and cash equivalents, beginning of year			61,348		89,945		116,743
Cash and cash equivalents, end of year		$	38,000	$	61,348	$	89,945

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

ENERPLUS 2022 FINANCIAL SUMMARY             9

      NOTES

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 United States (“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’ corporate offices are located in Calgary, Alberta, Canada and Denver, Colorado, United States.

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 U.S. (“U.S. GAAP”).

i. Reporting and Functional Currency

These Consolidated Financial Statements are presented in U.S. dollars, which is Enerplus’ reporting currency.

The functional currency of the parent entity is Canadian dollars and the functional currency of the U.S. subsidiaries is U.S. dollars. All references to $ or US$ are to U.S. dollars and references to CDN$ are to Canadian dollars. All financial information presented in U.S. and Canadian dollars has been rounded to the nearest thousand unless otherwise indicated.

Subsequent to the year ended December 31, 2022, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars effective January 1, 2023. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a prospective change in functional currency of the parent entity to U.S. dollars, consistent with the functional currency of its U.S. subsidiary.

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 those that relate to: 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, gains on asset divestments, impairment assessment 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 inputs and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Inflation and discount rates impacting various items within the Company’s financial statements are also subject to management estimation. When estimating the present value of future cash flows, the discount rate implicitly considers the potential impacts, if any, due to climate change factors. Enerplus uses the most current information available and exercises judgment in making 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.

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.

10             ENERPLUS 2022 FINANCIAL SUMMARY

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, with limited exceptions, at the acquisition date.

b) Revenue

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.

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. 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, in which case the Company would be the principal and the revenue is recognized on a gross basis. Any associated fees are recorded as an expense. 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.

All references to crude oil and natural gas revenue or production in the Consolidated Financial Statements are net of royalties.

c) Transportation

Enerplus generally sells crude oil and natural gas under two types of agreements which are common in 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).

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.

ENERPLUS 2022 FINANCIAL SUMMARY             11

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 or any other factors, as it is prescribed under U.S. GAAP. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain, and as such, it is difficult to determine the impact on estimated future net cash flows of such a transition.

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 certain circumstances, where the carrying value of the full cost centre exceeds the ceiling test limitation, the Company may seek a temporary waiver from the SEC to exclude certain amounts from the full cost ceiling limitation. The Company must demonstrate that the fair value of the excluded properties clearly exceeds the carrying value.

Under full cost accounting rules, divestments 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 is recognized.

e) Other Capital Assets

Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, and computer equipment. 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.

f) Other Long-term Assets

Other long-term assets include Company-owned line fill in third party pipelines and long-term receivables. Line fill is recorded at lower of cost and net realizable value.

g) Cash and Cash Equivalents

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

h) 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. 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.

i) Asset Retirement Obligations

Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning, reclamation, 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.

12             ENERPLUS 2022 FINANCIAL SUMMARY

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

j) Leases

Enerplus determines at inception, whether a business contract is an operating or finance lease, as defined under U.S. GAAP. 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.

Finance leases are recognized on the commencement date and included in right-of-use (“ROU”) assets and lease liabilities in the Consolidated Balance Sheets. 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 such leases. Lease liabilities are recognized at the present value of the lease payments over the lease term. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is more likely than not that it will exercise those options. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for payments made prior to lease commencement or initial direct costs, if any. When calculating the present value, Enerplus uses the rate implicit in the lease, or uses its incremental borrowing rate for a similar term and risk profile based on the information available at the commencement date.

Lease expense for operating leases is recognized on a straight-line basis over the lease term.

Lease agreements can contain both lease and non-lease components, which are accounted for separately. For certain equipment leases, a portfolio approach is applied to account for the ROU assets and liabilities.

k) 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.

The expected future taxable income considered in the analysis of the valuation allowance is based on cash flows from the proven and probable reserves and other sources of income. 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. Investment tax credits are applied using the flow-through method.

l) 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.

ENERPLUS 2022 FINANCIAL SUMMARY             13

ii. Non-derivative financial instruments

The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, bank credit facilities, and marketable securities reported on the Consolidated Balance Sheets approximates their fair value. The fair value of the senior notes and loan receivable are considered a level 2 fair value measurement and details are disclosed in Note 16. 

The Company uses the current expected credit loss model in valuing accounts receivable and loan 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 Statements 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 that is held in the parent entity as a hedge of its net investment in operations for which the U.S. dollar is the functional currency. As a non-derivative financial instrument, it 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 the fair value of the net investment in the U.S. subsidiary. If effective, the unrealized foreign exchange gains and losses arising from the translation of the U.S. denominated debt are recorded in Other Comprehensive Income/(Loss) (“OCI”), net of tax, to the extent the net investment in the U.S. subsidiary supports the U.S. denominated debt.

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).

In connection with the sale of certain Canadian assets during the year, the Company provided a loan to the purchaser. The loan receivable is recorded at its amortized cost basis on the Consolidated Balance Sheets.

Marketable securities are classified as held for trading and carried at fair value based on a level 1 designation, with changes in fair value recorded in Transaction costs and other expense/(income). When the instruments are ultimately sold any gains or losses are recognized in Transaction costs and other expense/(income).

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, 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/(loss). 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.

14             ENERPLUS 2022 FINANCIAL SUMMARY

m) Foreign Currency

i. Foreign currency transactions

Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars in Canada and U.S. dollars in the U.S.) 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/(loss) in the period in which they arise.

ii. Foreign currency translation

For financial statement presentation, assets and liabilities of Enerplus’ Canadian operations, which have a Canadian dollar functional currency, are translated into U.S. 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.

n) 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.

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 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.  

o) 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.

ENERPLUS 2022 FINANCIAL SUMMARY             15

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 outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price.

p) 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.

q) Government Assistance

In 2020, the Alberta, Saskatchewan, and British Columbia provincial governments created programs and provided funding to support the clean-up of inactive or abandoned crude oil and natural gas wells. Enerplus applied for and benefited from these programs in 2022 and 2021. The programs provide funding directly to oil field service contractors engaged by companies to perform abandonment, remediation, and reclamation work. As work is completed, the contractors submit invoices to the provincial government for reimbursement for the pre-approved funding amounts. Enerplus recognizes the assistance as the abandonment, remediation, and reclamation work is completed by the contractor. The benefit of the funding received by the contractor is reflected as a reduction of asset retirement obligation and recorded as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss).

3) ACQUISITIONS & DIVESTMENTS

a) Canadian Asset Divestments

On October 31, 2022, the Company completed a disposition of certain Canadian assets to Journey Energy Inc. (“Journey”) for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. The total consideration included cash of $59.3 million, 3.0 million common shares in Journey valued at $12.1 million, and a $33.0 million monthly amortizing, interest-bearing secured loan with a 10% fixed interest rate and maturity of October 31, 2024, which Enerplus provided to Journey. After purchase price adjustments and transaction costs, adjusted proceeds were $80.8 million resulting in a $64.5 million gain on asset divestments on the Consolidated Statements of Income/(Loss). The Company reduced the asset retirement obligation by $31.6 million. The Company divested of the common shares in Journey in the fourth quarter of 2022.

On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets to Surge Energy Inc. (“Surge”) for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. The total consideration included cash of $153.9 million and 3.8 million common shares in Surge valued at $20.7 million. After purchase price adjustments and transaction costs, adjusted proceeds were $132.2 million resulting in a $87.4 million gain on asset divestments on the Consolidated Statements of Income/(Loss). The Company reduced the asset retirement obligation by $26.5 million.

At December 31, 2022, the current and long-term portion of the outstanding loan receivable of $17.7 million and $13.4 million, respectively, have been recorded as part of Other current assets and Other long-term assets on the Consolidated Balance Sheets.

At December 31, 2022, the common shares of Surge had a fair value of $23.1 million resulting in an unrealized gain of $2.4 million, recognized in Transaction costs and other expense/(income) on the Consolidated Statements of Income/(Loss). The fair value of the marketable securities has been recorded as part of Other current assets on the Consolidated Balance Sheets.

b) Bruin E&P HoldCo, LLC Acquisition

On March 10, 2021, Enerplus Resources (USA) Corporation, an indirect wholly-owned subsidiary of Enerplus acquired all of the equity interests of Bruin E&P HoldCo, LLC (“Bruin”) for total cash consideration of $465.0 million, subject to certain purchase price adjustments. After purchase price adjustments, the total consideration was $420.2 million. The transaction was accounted for as an acquisition of a business.  

c) Dunn County Acquisition

On April 30, 2021, the Company acquired assets in Dunn County, North Dakota from Hess Bakken Investments II, LLC for total cash consideration of $312.0 million, subject to customary purchase price adjustments. After purchase price adjustments, the purchase consideration including capitalized transaction costs was $306.8 million. The transaction was recorded as an asset acquisition.

16             ENERPLUS 2022 FINANCIAL SUMMARY

d) Sleeping Giant and Russian Creek Divestment

On November 2, 2021, the Company completed a disposition of its interests in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, for total cash consideration of $115.0 million, subject to customary purchase price adjustments. After purchase price adjustments and transaction costs, adjusted proceeds were $107.8 million. Subsequent to December 31, 2022, Enerplus received $2.5 million in contingent consideration and may receive an additional $2.5 million if the WTI oil price averages over $60 per barrel in 2023. The fair value of the contingent consideration has been recorded as part of Other current assets and Other long-term assets.

4) ACCOUNTS RECEIVABLE

($ thousands)	December 31, 2022		December 31, 2021
Accrued revenue	$	244,494	$	208,160
Accounts receivable – trade		35,019		23,697
Allowance for doubtful accounts		(2,923)		(3,869)
Total accounts receivable, net of allowance for doubtful accounts	$	276,590	$	227,988

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

			Accumulated Depletion,
At December 31, 2022			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties(1)	$	13,023,018	$	(11,700,114)	$	1,322,904
Crude oil and natural gas properties – Canadian divestments(2)		(5,808,025)		5,808,025		—
Other capital assets		99,283		(88,598)		10,685
Total PP&E	$	7,314,276	$	(5,980,687)	$	1,333,589

			Accumulated Depletion,
At December 31, 2021			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties(1)	$	13,075,987	$	(11,822,482)	$	1,253,505
Other capital assets		103,355		(89,468)		13,887
Total PP&E	$	13,179,342	$	(11,911,950)	$	1,267,392

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

(2) The Company removed the Canadian cost centre’s historical PP&E balances upon the divestment of the Canadian assets.

Acquisitions:

For the years ended December 31, 2022 and 2021, Enerplus acquired property and land totaling $22.5 million and $857.1 million, respectively. Refer to Note 3 for details regarding the Bruin and Dunn County acquisitions during 2021.

Divestments:

For the years ended December 31, 2022 and 2021, Enerplus disposed of properties for proceeds of $231.4 million and $112.7 million, respectively. Certain asset divestments may result in gains if the divestments cause a significant alteration in the relationship between the cost centre’s capitalized costs and proved reserves. During 2022, Enerplus recognized gains on asset divestments of $151.9 million (2021 and 2020 – nil). Refer to Note 3 for details regarding the divestment of the Canadian assets in 2022 and the Sleeping Giant and Russian Creek assets in 2021.

6) IMPAIRMENT

a) Impairment of PP&E

($ thousands)	2022		2021		2020
Crude oil and natural gas properties:
U.S. cost centre	$	—	$	—	$	650,780
Canada cost centre		—		3,420		100,943
Total impairment expense	$	—	$	3,420	$	751,723

No asset impairment was recorded during the year ended December 31, 2022 (2021 – $3.4 million; 2020 – $751.7 million). The primary factors that affect ceiling values include first-day-of-the-month commodity prices, reserves, capital expenditure levels and timing, acquisition and divestment activity, and production levels.

ENERPLUS 2022 FINANCIAL SUMMARY             17

The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test at December 31, 2022, 2021 and 2020:

	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub Gas		Exchange Rate
Period	$/bbl		CDN$/bbl		$/Mcf		CDN$/US$
2022	$	94.14	$	119.13	$	6.25		0.77
2021		66.55		78.15		3.64		0.80
2020		39.54		45.56		2.00		0.75

b) Impairment of Goodwill

At December 31, 2022 and 2021, there was no goodwill remaining on the Company’s Consolidated Balance Sheets. During the year ended December 31, 2020, Enerplus recorded goodwill impairment of $149.2 million relating to its U.S. reporting unit. This was due to lower commodity prices in 2020, which resulted in a reduction in the fair value of the U.S. reporting unit.

7) ACCOUNTS PAYABLE

($ thousands)	December 31, 2022		December 31, 2021
Accrued payables	$	110,267	$	106,222
Accounts payable – trade		288,215		260,786
Total accounts payable	$	398,482	$	367,008

8) DEBT

($ thousands)	December 31, 2022		December 31, 2021
Current:
Senior notes	$	80,600	$	100,600
Long-term:
Bank credit facilities		56,316		397,971
Senior notes		122,600		203,200
Total debt	$	259,516	$	701,771

Bank Credit Facilities

In February 2022, Enerplus converted its senior unsecured, covenant-based, $400 million term loan maturing on March 10, 2024 into a revolving bank credit facility with no other amendments. In November 2022, Enerplus converted this $400 million revolving bank credit facility to a $365 million sustainability-linked lending (“SLL”) bank credit facility and extended the maturity to October 31, 2025. The $365 million SLL bank credit facility has the same targets as Enerplus’ $900 million SLL bank credit facility. There were no other significant amendments or additions to the agreement’s terms or covenants. Debt issuance costs were netted against the debt on issuance and are being amortized over the three-year term with $1.5 million of unamortized debt issuance costs remaining at December 31, 2022.

Enerplus also has a senior unsecured, covenant-based, $900 million SLL bank credit facility, which was renewed in November 2022, with $50 million maturing on October 31, 2025, and $850 million maturing on October 31, 2026. There were no other significant amendments or additions to the agreement’s terms or covenants. Debt issuance costs in relation to the SLL bank credit facility were netted against the debt on issuance and are being amortized over the four year term with $1.7 million of unamortized debt issuance costs remaining at December 31, 2022.  

The SLL bank credit facilities incorporate environmental, social and governance (“ESG”)-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus’ sustainability performance targets (“SPT”) are exceeded or missed. The SPTs are based on the following ESG goals of the Company:

● GHG Emissions: continuous progress toward Enerplus’ stated goal of a 35% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2021 as a baseline and measurement based on Enerplus’ annual internal targets;

● Water Management: achieve a 50% reduction in freshwater usage in corporate well completions by 2025 or earlier compared to 2019; and

● Health & Safety: achieve and maintain a 25% reduction in the Company’s Lost Time Injury Frequency, based on a trailing 3-year average, relative to a 2019 baseline.

18             ENERPLUS 2022 FINANCIAL SUMMARY

For the year ended December 31, 2022, total amortization of debt issuance costs amounted to $1.5 million (December 31, 2021 – $1.1 million).

Senior Notes

During 2022, Enerplus made a $21.0 million principal repayment on its 2014 senior notes. In addition, Enerplus made its third $59.6 million principal repayment and a $20.0 million bullet payment on its 2012 senior notes.

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

				Original	Remaining
			Coupon	Principal	Principal
Issue Date	Interest Payment Dates	Principal Repayment	Rate	($ thousands)	($ thousands)
September 3, 2014	March 3 and Sept 3	4 equal annual installments beginning September 3, 2023	3.79%	$200,000	$84,000
May 15, 2012	May 15 and Nov 15	2 equal annual installments beginning May 15, 2023	4.40%	$355,000	$119,200
		Total carrying value at December 31, 2022			$ 203,200

Capital Management

Enerplus' capital consists of cash and cash equivalents, debt and shareholders' equity. The Company’s objective for managing capital is to prioritize balance sheet strength while maintaining flexibility to repay debt, fund sustaining capital, return capital to shareholders or fund future production growth. Capital management measures are useful to investors and securities analysts in analyzing operating and financial performance, leverage, and liquidity. Enerplus’ key capital management measures are as follows:

a) Net Debt

Enerplus calculates net debt as current and long-term debt associated with senior notes plus any outstanding bank credit facility balances, minus cash and cash equivalents.

($ thousands)	December 31, 2022		December 31, 2021
Current portion of long-term debt	$	80,600	$	100,600
Long-term debt		178,916		601,171
Total debt	$	259,516	$	701,771
Less: Cash and cash equivalents		(38,000)		(61,348)
Net debt	$	221,516	$	640,423

b) Adjusted funds flow

Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.

($ thousands)		2022		2021		2020
Cash flow from/(used in) operating activities	$	1,173,382	$	604,839	$	335,884
Asset retirement obligation settlements		17,401		12,951		13,275
Changes in non-cash operating working capital		39,506		94,643		(83,669)
Adjusted funds flow	$	1,230,289	$	712,433	$	265,490

c) Net debt to adjusted funds flow ratio

The net debt to adjusted funds flow ratio is calculated as net debt divided by a trailing twelve months of adjusted funds flow.

($thousands)	December 31, 2022		December 31, 2021
Net debt	$	221,516	$	640,423
Trailing adjusted funds flow		1,230,289		712,433
Net debt to adjusted funds flow ratio	$	0.2x	$	0.9x

ENERPLUS 2022 FINANCIAL SUMMARY             19

9) ASSET RETIREMENT OBLIGATION (“ARO”)

($ thousands)	December 31, 2022		December 31, 2021
Balance, beginning of year	$	132,814	$	102,325
Change in estimates		48,419		26,586
Property acquisition and development activity		3,985		1,304
Bruin acquisition (Note 3)		—		21,964
Dunn County acquisition (Note 3)		—		5,880
Divestments (Note 3)		(58,284)		(13,525)
Settlements		(17,401)		(12,951)
Government assistance		(1,744)		(4,594)
Accretion expense		6,873		5,825
Balance, end of year	$	114,662	$	132,814

Enerplus has estimated the present value of its asset retirement obligation to be $114.7 million at December 31, 2022 based on a total undiscounted, uninflated liability of $262.4 million (December 31, 2021 – $132.8 million and $303.3 million, respectively). Enerplus’ asset retirement obligation expenditures are mainly expected to be incurred between 2023 – 2034 and 2037 – 2053.

Enerplus benefited from provincial government assistance to support the clean-up of inactive or abandoned crude oil and natural gas wells. These programs provide funding directly to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. For the year ended December 31, 2022, Enerplus benefited from $1.7 million (2021 – $4.6 million, 2020 – nil) in government assistance, which has been recorded as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss).

During 2022, Enerplus recognized $13.1 million as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss) to fund abandonment and reclamation obligation requirements on previously disposed of assets (2021 and 2020 – nil).

10) LEASES

The Company has entered into various lease contracts 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 Sheets. Such items are charged to operating expenses or general and administrative expenses, as appropriate, in the Consolidated Statements of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with U.S. GAAP.

($ thousands)	December 31, 2022		December 31, 2021
Assets
Operating right-of-use assets	$	20,556	$	26,118
Liabilities
Current operating lease liabilities	$	13,664	$	10,618
Non-current operating lease liabilities		9,262		18,265
Total lease liabilities	$	22,926	$	28,883
Weighted average remaining lease term (years)
Operating leases		2.4		3.3
Weighted average discount rate
Operating leases		3.7%		3.4%

20             ENERPLUS 2022 FINANCIAL SUMMARY

The Company’s lease contract expenditures/(income) for the years ended December 31, 2022 and 2021 are as follows:

($ thousands)	2022		2021
Operating lease cost	$	12,409	$	11,378
Variable lease cost		3,847		633
Short-term lease cost		7,163		3,469
Sublease income		(1,091)		(1,083)
Total	$	22,328	$	14,397

Variable lease payments are determined through analysis of day rate fees under applicable rig contracts. The amounts in the table above are recorded as part of general and administrative or operating expenses or property, plant, and equipment depending on the nature of the contract to which they relate. Although Enerplus has various leases containing extensions and/or termination options, none were determined to be reasonably certain to be exercised. As a result, none of these options are recognized as part of the ROU assets or lease liabilities at December 31, 2022 or 2021.

Maturities of lease liabilities, all of which are classified as operating leases at December 31, 2022, are as follows:

($ thousands)	Operating Leases
2023	$	14,278
2024		6,475
2025		1,099
2026		966
2027		988
After 2027		165
Total lease payments	$	23,971
Less imputed interest		(1,045)
Total discounted lease payments	$	22,926
Current portion of lease liabilities	$	13,664
Non-current portion of lease liabilities	$	9,262

Supplemental information related to leases is as follows:

($ thousands)	2022			2021
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases	$	10,552	$	11,571
Right-of-use assets obtained/(terminated) in exchange for lease liabilities:
Operating leases	$	5,651	$	10,030

11) CRUDE OIL AND NATURAL GAS SALES

Crude oil and natural gas sales by country and by product for the years ended December 31, 2022, 2021 and 2020 are as follows:

2022						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	2,205,876	$	1,646,453	$	455,678	$	103,731	$	14
Canada		147,498		131,283		10,918		4,760		537
Total	$	2,353,374	$	1,777,736	$	466,596	$	108,491	$	551

2021						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	1,355,255	$	1,055,748	$	219,552	$	79,930	$	25
Canada		127,320		111,070		11,127		4,348		775
Total	$	1,482,575	$	1,166,818	$	230,679	$	84,278	$	800

ENERPLUS 2022 FINANCIAL SUMMARY             21

2020						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	480,822	$	380,074	$	92,453	$	8,182	$	113
Canada		72,917		59,642		9,239		2,591		1,445
Total	$	553,739	$	439,716	$	101,692	$	10,773	$	1,558

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

(2) Includes third party processing income.

12) GENERAL AND ADMINISTRATIVE EXPENSE

($ thousands)	2022		2021		2020
General and administrative expense excluding share-based compensation(1)	$	42,374	$	38,013	$	33,347
Share-based compensation expense		27,580		18,794		9,750
General and administrative expense	$	69,954	$	56,807	$	43,097

(1) Includes non-cash lease credit of $395 in 2022, $365 in 2021, $212 in 2020.

13) FOREIGN EXCHANGE

($ thousands)	2022		2021		2020
Realized:
Foreign exchange (gain)/loss	$	(121)	$	3,477	$	771
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company		(937)		(2,330)		(902)
Unrealized:
Foreign exchange (gain)/loss on U.S. dollar working capital in parent company		11,217		(8,055)		1,363
Foreign exchange (gain)/loss	$	10,159	$	(6,908)	$	1,232

14) INCOME TAXES

Enerplus’ provision for income tax is as follows:

($ thousands)	2022		2021		2020
Current tax
United States	$	28,063	$	2,700	$	(10,716)
Canada		—		(11)		—
Current tax expense/(recovery)		28,063		2,689		(10,716)
Deferred tax
United States	$	217,943	$	148,920	$	(167,835)
Canada		47,290		(50,165)		(20,425)
Deferred tax expense/(recovery)		265,233		98,755		(188,260)
Income tax expense/(recovery)	$	293,296	$	101,444	$	(198,976)

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

($ thousands)	2022		2021		2020
Income/(loss) before taxes
United States	$	966,646	$	544,464	$	(877,406)
Canada		240,952		(208,579)		(14,921)
Total income/(loss) before taxes		1,207,598		335,885		(892,327)
Canadian statutory rate		23%		24%		24%
Expected income tax expense/(recovery)	$	277,748	$	80,612		(214,158)
Impact on taxes resulting from:
Foreign and statutory rate differences	$	35,636	$	19,297	$	(27,918)
Investment tax credit		(14,245)		—		(9,639)
Non-taxable capital (gains)/losses		(184)		(105)		14,341
Change in valuation allowance		291		(560)		(25,918)
Goodwill impairment, share-based compensation and other		(5,950)		2,200		64,317
Income tax expense/(recovery)	$	293,296	$	101,444	$	(198,976)

22             ENERPLUS 2022 FINANCIAL SUMMARY

The deferred income tax asset/(liability) consists of the following:

At December 31 ($ thousands)	2022		2021
Canadian deferred income tax asset/(liability)
Property, plant and equipment	$	40,207	$	125,311
Tax loss carry-forwards and other credits		101,909		40,891
Capital loss carryforwards and other capital items		101,078		107,681
Asset retirement obligation		11,368		17,368
Derivative financial instruments		(6,578)		28,907
Other		6,442		10,966
Valuation allowance		(99,428)		(112,847)
Canadian deferred income tax asset/(liability)		154,998		218,276
United States deferred income tax asset/(liability)
Property, plant and equipment	$	(77,868)	$	(45,824)
Tax loss carry-forwards and other credits		1,785		200,057
Asset retirement obligation		15,645		15,528
Other		5,077		(7,180)
United States deferred income tax asset/(liability)		(55,361)		162,582
Total deferred income tax asset/(liability)	$	99,637	$	380,858

Loss carry-forwards available for tax reporting purposes:

At December 31 ($ thousands)	2022		Expiration Date
Canada Federal
Non-capital losses	$	365,000	2031-2042

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

($ thousands)	2022		2021		2020
Balance, beginning of year	$	15,485	$	15,485	$	—
Increase – tax positions in prior periods		—		—		15,485
Balance, end of year	$	15,485	$	15,485	$	15,485

If recognized, all of Enerplus’ unrecognized tax benefits at December 31, 2022 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
United States – Federal	2019-2022
Canada – Federal	2018-2022

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.

ENERPLUS 2022 FINANCIAL SUMMARY             23

15) SHAREHOLDERS’ EQUITY

a) Share Capital

	2022			2021			2020
(thousands)	Shares	Amount		Shares	Amount		Shares	Amount
Balance, beginning of year	243,852	$	3,094,061	222,548	$	3,113,829	221,744	$	3,106,875
Issued/(Purchased) for cash:
Purchase of common shares under Normal Course Issuer Bid	(27,925)		(266,694)	(12,898)		(128,686)	(340)		(3,582)
Issue of shares (net of tax effected issue costs)	—		—	33,062		99,516	—		—
Non-cash:
Share-based compensation – treasury settled(1)	1,358		9,962	1,140		9,402	1,160		10,694
Cancellation of predecessor shares	—		—	—		—	(16)		(158)
Balance, end of year	217,285	$	2,837,329	243,852	$	3,094,061	222,548	$	3,113,829

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

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

For the year ended December 31, 2022, Enerplus declared dividends of $0.181 per weighted average common share totaling $41.6 million (2021 – $0.121 per share and $30.5 million; 2020 – $0.090 per share and $20.0 million).  Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share, to be paid in March 2023.

On August 16, 2022 Enerplus renewed its Normal Course Issuer Bid (“NCIB”) to purchase up to 10% of the public float (within the meaning under Toronto Stock Exchange rules) during a 12-month period. Enerplus completed its previous NCIB in July 2022. For the year ended December 31, 2022, 27,924,842 common shares were repurchased and cancelled under the NCIB at an average price of $14.71 per share, for total consideration of $410.9 million. Of the amount paid, $266.7 million was charged to share capital and $144.2 million was added to accumulated deficit. At December 31, 2022, 7,883,479 common shares are available for repurchase under the current NCIB.

For the year ended December 31, 2021, the Company repurchased 12,897,721 common shares under the NCIB at an average price of $9.55 per share, for total consideration of $123.2 million. Of the amount paid, $128.7 million was charged to share capital and $5.5 million was credited to accumulated deficit.

For the year ended December 31, 2020, the Company repurchased 340,434 common shares under the former NCIB at an average price of $5.63 per share, for total consideration of $1.9 million. Of the amount paid, $3.6 million was charged to share capital and $1.7 million was credited to accumulated deficit.

Subsequent to December 31, 2022 and up to and including February 22, 2023, the Company repurchased 1,420,927 common shares under the current NCIB at an average price of $16.65 per share, for total consideration of $23.7 million.

For the year ended December 31, 2021, Enerplus issued 33,062,500 common shares at a price of CDN$4.00 per common share  for gross proceeds of $103.4 million (net $99.5 million, after $5.1 million in issue costs, net of $1.2 million in tax) pursuant to a bought deal prospectus offering under its base shelf prospectus.

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)	2022		2021		2020
Cash:
Long-term incentive plans (recovery)/expense	$	5,664	$	6,875	$	(934)
Non-Cash:
Long-term incentive plans expense		22,924		13,789		9,720
Equity swap (gain)/loss		(1,008)		(1,870)		964
Share-based compensation expense	$	27,580	$	18,794	$	9,750

24             ENERPLUS 2022 FINANCIAL SUMMARY

LTI Plans

The following table summarizes the PSU, RSU, DSU and DRSU activity for the year ended December 31, 2022:

For the year ended December 31, 2022	Cash-settled LTI Plans	Equity-settled LTI Plans		Total
(thousands of units)	DSU/DRSU	PSU(1)	RSU
Balance, beginning of year	589	3,981	3,065	7,635
Granted	89	809	837	1,735
Vested	(45)	(1,030)	(1,316)	(2,391)
Forfeited	—	(71)	(265)	(336)
Balance, end of year	633	3,689	2,321	6,643

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

Cash-settled LTI Plans

For the year ended December 31, 2022, the Company recorded a cash share-based compensation expense of $5.7 million (2021 – expense of $6.9 million; 2020 – recovery of $0.9 million).

At December 31, 2022, a liability of $11.1 million (December 31, 2021 – $6.3 million) with respect to the Director DSU and DRSU Plans 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 as 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, 2022 ($ thousands, except for years)	PSU(1)		RSU		Total
Cumulative recognized share-based compensation expense	$	21,616	$	10,368	$	31,984
Unrecognized share-based compensation expense		11,815		4,136		15,951
Fair value	$	33,431	$	14,504	$	47,935
Weighted-average remaining contractual term (years)		1.2		0.9

(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, 2022,  $13.4 million (2021 – $3.6 million; 2020 – $5.6 million) in cash withholding taxes were paid.

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

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

(thousands, except per share amounts)	2022		2021		2020
Net income/(loss)	$	914,302	$	234,441	$	(693,351)
Weighted average shares outstanding – Basic		233,946		251,909		222,503
Dilutive impact of share-based compensation(1)		8,727		7,942		—
Weighted average shares outstanding – Diluted		242,673		259,851		222,503
Net income/(loss) per share
Basic	$	3.91	$	0.93	$	(3.12)
Diluted	$	3.77	$	0.90	$	(3.12)

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

ENERPLUS 2022 FINANCIAL SUMMARY             25

16) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At December 31, 2022, the carrying value of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term nature of these instruments. The fair values of the bank credit facilities approximate their carrying values as they bear interest at floating rates and the credit spread approximates current market rates.

At December 31, 2022, the senior notes had a carrying value of $203.2 million and a fair value of $189.5 million (December 31, 2021 – $303.8 million and $304.1 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.

At December 31, 2022, the loan receivable had a carrying value of $31.1 million and a fair value of $31.6 million (December 31, 2022 – nil). The fair value of the loan receivable is estimated based on the amount that Enerplus would receive from a third party to assume the loan, including the difference between the coupon rate and the period end market rate for loan receivables of similar terms and credit risk.

The fair value of marketable securities are considered level 1 fair value measurements, while the derivative contracts, senior notes, bank credit facilities and loan receivable are considered level 2 fair value measurements. 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 table summarizes the change in fair value associated with equity and commodity contracts for the respective years:

							Income
Gain/(Loss) ($ thousands)	2022		2021		2020		Statement Presentation
Equity Swaps	$	1,008	$	1,870	$	(964)	G&A expense
Commodity Contracts:
Crude oil		125,842		(111,655)		(19,891)	Commodity derivative
Natural gas		23,676		249		2,781	instruments
Total Unrealized Gain/(Loss)	$	150,526	$	(109,536)	$	(18,074)

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

($ thousands)	2022		2021		2020
Unrealized change in fair value gain/(loss)	$	149,518	$	(111,406)	$	(17,110)
Net realized cash gain/(loss)		(347,204)		(163,026)		92,852
Commodity contracts gain/(loss)	$	(197,686)	$	(274,432)	$	75,742

The following table summarizes the presentation of fair values on the Consolidated Balance Sheets:

	December 31, 2022				December 31, 2021
	Assets		Liabilities			Assets		Liabilities
($ thousands)	Current		Current			Current		Current		Long-term
Equity Swaps	$	—	$	—		$	—	$	969	$	—
Commodity Contracts:
Crude oil		9,834		10,421			1,771		141,364		7,098
Natural gas		26,708		—			3,897		867		—
Total	$	36,542	$	10,421		$	5,668	$	143,200	$	7,098

The fair value of commodity contracts and the equity swaps is estimated based on commodity and option pricing models that incorporate various factors including forecasted commodity prices, volatility and the credit risk of the entities party to the contract. Changes and variability 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.

26             ENERPLUS 2022 FINANCIAL SUMMARY

At December 31, 2022, the fair value of Enerplus’ commodity contracts totaled a net asset of $26.1 million (December 31, 2021 – net liability $143.7 million). This balance included a liability of $10.1 million (December 31, 2021 – $40.2 million) related to Bruin contracts, with $2.7 million (December 31, 2021 – $22.8 million) remaining from the original $76.4 million liability acquired from Bruin on March 10, 2021.

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, liquidity risk, and the risks associated with environmental/climate change risk, social and governance regulation, and compliance.  

i) Market Risk

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

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.

The following tables summarize Enerplus’ price risk management positions at February 22, 2023:

Crude Oil Instruments:

Instrument Type(1)(2)
	Jan 1, 2023 - Jun 30, 2023		Jul 1, 2023 - Oct 31, 2023		Nov 1, 2023 - Dec 31, 2023
	bbls/day	$/bbl	bbls/day	$/bbl	bbls/day	$/bbl
WTI Purchased Put	15,000	79.33	5,000	85.00	5,000	85.00
WTI Sold Put	15,000	61.67	5,000	65.00	5,000	65.00
WTI Sold Call	15,000	114.31	5,000	128.16	5,000	128.16
Brent – WTI Spread	10,000	5.47	10,000	5.47	10,000	5.47
WTI Purchased Swap	250	64.85	250	64.85	—	—
WTI Sold Swap(3)	250	42.10	250	42.10	—	—
WTI Purchased Put(3)	2,000	5.00	2,000	5.00	2,000	5.00
WTI Sold Call(3)	2,000	75.00	2,000	75.00	2,000	75.00

(1) The total average deferred premium spent on the Company’s outstanding crude oil contracts is $1.25/bbl from January 1, 2023 – December 31, 2023.

(2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes.

(3) Outstanding commodity derivative instruments acquired as part of the Bruin Acquisition.

Natural Gas Instruments:

Instrument Type(1)	Jan 1, 2023 – Jan 31, 2023		Feb 1, 2023 – Feb 28, 2023		Mar 1, 2023 – Mar 31, 2023
	MMcf/day	$/Mcf	MMcf/day	$/Mcf	MMcf/day	$/Mcf
NYMEX Purchased Swap	—	—	120.0	3.10	120.0	2.44
NYMEX Purchased Put	120.0	6.27	120.0	6.27	120.0	6.27
NYMEX Sold Call	120.0	18.17	120.0	18.17	120.0	18.17
TZ6 NNY Basis Swap	—	—	—	—	12.5	0.41

(1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

Instrument Type(1)	Apr 1, 2023 – Oct 31, 2023
	MMcf/day	$/Mcf
NYMEX Purchased Put	50.0	4.05
NYMEX Sold Call	50.0	7.00

(1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

ENERPLUS 2022 FINANCIAL SUMMARY             27

Foreign Exchange Risk & Net Investment Hedge:

Enerplus is exposed to foreign exchange risk as it relates to certain activity transacted in Canadian or United States dollars. Enerplus has a U.S. dollar reporting currency, however Enerplus’ parent company has a Canadian functional currency until December 31, 2022. Activity in the Canadian parent company that is transacted in U.S. dollars results in realized and unrealized foreign exchange gains and losses and is recorded on the Consolidated Statements of Income/(Loss).

Enerplus may designate certain U.S. dollar denominated debt held in the parent entity as a hedge of its net investment in its U.S. subsidiary, which has a U.S. dollar functional currency. 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 by the cumulative translation gain or loss on the net investment in the foreign subsidiary. At December 31, 2022, $203.2 million of senior notes and the $56.3 million drawn on the bank credit facilities were designated as net investment hedges (2021 – $303.8 million of senior notes and $400 million of the term loan). For the year ended December 31, 2022, Other Comprehensive Income/(Loss) included an unrealized loss of $26.5 million on Enerplus’ U.S. denominated senior notes and bank credit facilities (2021 – $4.1 million gain and 2020 – $1.8 million gain).

Interest Rate Risk:

The Company’s senior notes bear interest at fixed rates while the bank credit facilities bear interest at floating rates.  At December 31, 2022, approximately 78% of Enerplus’ debt was based on fixed interest rates and 22% on floating interest rates (December 31, 2021 – 43% fixed and 57% floating), with weighted average interest rates of 4.2% and 5.7%, respectively (December 31, 2021 – 4.2% and 1.9%, respectively). At December 31, 2022 and 2021, Enerplus did not have any interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 15. The Company may enter into various equity swaps to fix the future settlement cost on a portion of its cash settled LTI plans. At December 31, 2022, Enerplus did not have any equity swaps outstanding.

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, divestments and financial counterparty receivables. Enerplus has appropriate policies and procedures in place to manage its credit risk; however, given the volatility in commodity prices, Enerplus is subject to an increased risk of financial loss due to non-performance or insolvency of its counterparties.

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.

The Company’s maximum credit exposure consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At December 31, 2022, approximately 90% of Enerplus’ marketing receivables were with companies considered investment grade (December 31, 2021 – 83%).

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, 2022 was $2.9 million (December 31, 2021 – $3.9 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 crude oil and natural gas assets and planned investment opportunities.

28             ENERPLUS 2022 FINANCIAL SUMMARY

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, 2022, Enerplus was in full compliance with all covenants under the bank credit facilities and outstanding senior notes. If the Company breaches or anticipates breaching its covenants, the Company may be required to repay, refinance, or renegotiate the terms of the debt.

iv) Climate Change Risk

The following provides certain considerations as to the impact of climate change on the amounts recorded in the financial statements for the year ended December 31, 2022. The below is not a comprehensive list or analysis of all climate change impacts and risks. In addition, the focus is with respect to the impact of climate change on amounts recognized in the Company’s financial statements as at and for the year ended December 31, 2022.

Changing regulation

Emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. The Canadian Securities Administrators have issued proposed National Instrument 51-107 Disclosure of Climate-related Matters and the U.S. Securities and Exchange Commission has issued proposed Rule 33-11042 The Enhancement and Standardization of Climate-Related Disclosures for Investors. The cost to comply with these standards, and others that may be developed or evolve over time, has not been quantified.

Impact of climate events and change on amounts recorded in the 2022 financial statements

Reserves:

The Company engages a third party external reserve engineer to review the reserve report. Enerplus considers the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in its assessment of economic recovery of crude oil and natural gas reserves. The reserve report includes anticipated impacts from emissions related taxes, most notably the reserve report includes estimated carbon tax related to the Company’s operations.

Ceiling test:

Given the prescriptive nature of the ceiling test and depletion calculations, climate change risk is only considered in the determination of reserves, which will impact the ceiling test and depletion calculations. At December 31, 2022, no impairment was recorded as a result of the ceiling test completed. See Note 6 for further detail.

Expenditures on property, plant and equipment:

The Company incurs capital expenditures related to emissions reduction initiatives. The extent of spending on projects directly linked to reducing the climate impact of the Company’s operations will vary, however, management anticipates funding future projects through cash flow from operations and bank credit facilities.

Current assets and current liabilities:

These amounts are short term in nature and management is not aware of any material impacts on these items related to climate change and climate events. The Company did not experience material credit losses on its accounts receivable during 2022.

Access to Capital:

There is risk that access to capital may be restricted to the oil and gas industry. Management plans to continue to monitor and adjust the capital structure where necessary. At December 31, 2022, Enerplus had two SLL bank credit facilities with three sustainability performance targets. See Note 8 for further detail.  

Physical effects of climate events (i.e. fire, flood, extreme weather) on the financial results

The Company’s financial results for 2022 were not materially impacted by a climate event.

ENERPLUS 2022 FINANCIAL SUMMARY             29

17) COMMITMENTS AND CONTINGENCIES

a) Commitments

Enerplus has the following minimum annual commitments, excluding operating leases which are recorded in the lease liability (see Note 10):

			Minimum Annual Commitment Each Year
($ thousands)		Total	2023		2024		2025		2026		2027		Thereafter
Senior notes(1)	$	203,200	$	80,600	$	80,600	$	21,000	$	21,000	$	—	$	—
Transportation commitments		487,604		71,329		72,598		73,428		73,975		61,852		134,422
Service workover rigs commitments		7,884		7,884		—		—		—		—		—
Purchase commitments		2,100		2,100		—		—		—		—		—
Total commitments(2)	$	700,788	$	161,913	$	153,198	$	94,428	$	94,975	$	61,852	$	134,422

(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.

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.

18) GEOGRAPHICAL INFORMATION

As at and for the year ended December 31, 2022 ($ thousands)	U.S.		Canada		Total
Crude oil and natural gas sales	$	2,205,876	$	147,498	$	2,353,374
Depletion, depreciation and accretion		286,438		22,929		309,367
Property, plant and equipment		1,329,545		4,044		1,333,589
Deferred income tax asset		—		154,998		154,998
Deferred income tax liability		55,361		—		55,361

As at and for the year ended December 31, 2021 ($ thousands)		U.S.		Canada		Total
Crude oil and natural gas sales	$	1,355,255	$	127,320	$	1,482,575
Depletion, depreciation and accretion		246,949		24,387		271,336
Property, plant and equipment		1,179,070		88,322		1,267,392
Deferred income tax asset		162,582		218,276		380,858

As at and for the year ended December 31, 2020 ($ thousands)		U.S.		Canada		Total
Crude oil and natural gas sales	$	480,822	$	72,917	$	553,739
Depletion, depreciation and accretion		183,226		34,892		218,118
Property, plant and equipment		375,634		88,167		463,801
Deferred income tax asset		311,502		165,512		477,014

19) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Accounts receivable	$	(45,837)	$	(144,413)	$	84,685
Other assets		(2,442)		(7,583)		(3,333)
Accounts payable – operating		8,773		57,353		2,317
Non-cash operating activities	$	(39,506)	$	(94,643)	$	83,669

30             ENERPLUS 2022 FINANCIAL SUMMARY

b) Changes in Non-Cash Financing Working Capital

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Dividends payable	$	—	$	(1,749)	$	65
Non-cash financing activities	$	—	$	(1,749)	$	65

c) Changes in Non-Cash Investing Working Capital  

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Accounts payable – investing(1)	$	3,420	$	32,793	$	(28,390)

(1) 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.

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Settlement on divestment'(1)	$	(13,053)	$	—	$	—

(1) Relates to funding abandonment and reclamation obligation requirements on previously disposed assets. Refer to Note 9.

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Loan receivable	$	(31,172)	$	—	$	—
Marketable securities		(20,654)		—		—
Accounts receivable		(3,128)		—		—
Non-cash working capital – Canadian divestments(1)	$	(54,954)	$	—	$	—

(1) Refer to Note 3.

d) Cash Income taxes and Interest payments

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Income taxes paid/(received)	$	26,061	$	5,500	$	(42,716)
Interest paid	$	24,399	$	25,808	$	21,276

e) Other

During the year ended December 31, 2021, Enerplus received a $4.6 million distribution associated with a privately held investment. This distribution was recorded within Transaction costs and other expense/(income) on the Consolidated Statements of Income/(Loss), and reflected as an investing activity in the Consolidated Statements of Cash Flows.

ENERPLUS 2022 FINANCIAL SUMMARY             31

EX-99.3

       2022 FINANCIAL SUMMARY

Exhibit 99.3

	Three months ended				Twelve months ended
SELECTED FINANCIAL RESULTS	December 31,				December 31,
	2022		2021		2022		2021
Financial (US$, thousands, except ratios)
Net Income/(Loss)	$	330,708	$	176,913	$	914,302	$	234,441
Adjusted Net Income(1)		181,069		129,958		707,061		315,669
Cash Flow from Operating Activities		316,584		283,534		1,173,382		604,839
Adjusted Funds Flow		315,379		258,477		1,230,289		712,433
Dividends to Shareholders - Declared		12,223		7,884		41,597		30,535
Net Debt		221,516		640,423		221,516		640,423
Capital Spending		85,647		81,059		432,004		302,348
Property and Land Acquisitions		2,853		2,744		22,515		835,147
Property and Land Divestments		211,987		108,869		231,373		112,651
Net Debt to Adjusted Funds Flow Ratio		0.2x		0.9x		0.2x		0.9x
Financial per Weighted Average Shares Outstanding
Net Income/(Loss) - Basic	$	1.49	$	0.71	$	3.91	$	0.93
Net Income/(Loss) - Diluted		1.43		0.68		3.77		0.90
Weighted Average Number of Shares Outstanding (000’s) - Basic		222,404		250,359		233,946		251,909
Weighted Average Number of Shares Outstanding (000’s) - Diluted		231,149		258,365		242,673		259,851
Selected Financial Results per BOE(2)(3)
Crude Oil & Natural Gas Sales(4)	$	55.78	$	52.82	$	64.27	$	44.04
Commodity Derivative Instruments		(4.83)		(7.12)		(9.48)		(4.84)
Operating Expenses		(9.68)		(8.46)		(9.99)		(8.69)
Transportation Costs		(4.04)		(4.27)		(4.22)		(3.81)
Production Taxes		(4.03)		(3.47)		(4.56)		(3.03)
General and Administrative Expenses		(1.15)		(1.12)		(1.17)		(1.14)
Cash Share-Based Compensation		(0.21)		(0.22)		(0.16)		(0.20)
Interest, Foreign Exchange and Other Expenses		0.56		(0.82)		(0.32)		(1.08)
Current Income Tax Recovery/(Expense)		(0.34)		(0.02)		(0.77)		(0.08)
Adjusted Funds Flow	$	32.06	$	27.32	$	33.60	$	21.17

	Three months ended				Twelve months ended
SELECTED OPERATING RESULTS	December 31,				December 31,
	2022		2021		2022		2021
Average Daily Production(3)
Crude Oil (bbls/day)		54,601		55,419		52,017		48,514
Natural Gas Liquids (bbls/day)		10,755		9,540		9,681		7,823
Natural Gas (Mcf/day)		249,351		227,186		231,770		215,304
Total (BOE/day)		106,915		102,823		100,326		92,221
% Crude Oil and Natural Gas Liquids		61%		63%		61%		61%
Average Selling Price(3)(4)
Crude Oil (per bbl)	$	83.06	$	75.21	$	93.63	$	65.89
Natural Gas Liquids (per bbl)		21.88		38.77		30.70		29.51
Natural Gas (per Mcf)		4.76		3.92		5.51		2.94
Net Wells Drilled		9.9		10.0		51.7		25.0

(1) This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section in the following MD&A.

(2) Non-cash amounts have been excluded.

(3) Based on net production volumes. See “Basis of Presentation” section in the following MD&A.

(4) Before transportation costs and commodity derivative instruments.

ENERPLUS 2022 FINANCIAL SUMMARY             1

	Three months ended				Twelve months ended
	December 31,				December 31,
Average Benchmark Pricing	2022		2021		2022		2021
WTI Crude Oil ($/bbl)	$	82.65	$	77.19	$	94.23	$	67.92
Brent (ICE) Crude Oil ($/bbl)		88.60		79.80		98.89		70.79
Propane – Conway ($/bbl)		34.21		52.42		46.03		43.74
NYMEX Natural Gas – Last Day ($/Mcf)		6.26		5.83		6.64		3.84
CDN/US Average Exchange Rate		0.74		0.79		0.77		0.80

Share Trading Summary	U.S.(1) – ERF		CDN(2) – ERF
For the twelve months ended December 31, 2022	(US$)		(CDN$)
High	$	19.23	$	25.72
Low	$	10.21	$	12.96
Close	$	17.65	$	23.90

(1) NYSE and other U.S. trading data combined.

(2) TSX and other Canadian trading data combined.

2022 Dividends Declared per Share		US$		CDN$(1)
First Quarter Total	$	0.033	$	0.042
Second Quarter Total	$	0.043	$	0.056
Third Quarter Total	$	0.050	$	0.066
Fourth Quarter Total	$	0.055	$	0.075
Total Year to Date	$	0.181	$	0.239

(1) CDN$ dividends converted at the relevant foreign exchange rate closer to the payment date.

2ENERPLUS 2022 FINANCIAL SUMMARY

       2022 HIGHLIGHTS

FINANCIAL & OPERATIONAL HIGHLIGHTS

● We delivered 2022 total production of 100,326 BOE/day, which was in line with our revised production guidance range (99,750 BOE/day to 101,000 BOE/day). Total production in 2022 was 9% higher compared to 2021. Crude oil and natural gas liquids production in 2022 was 61,698 bbls/day, which was in line with our revised guidance range (61,500 bbls/day to 62,500 bbls/day) and 10% higher compared to 2021. The higher year-over-year production was primarily due to a full period of production from the acquisitions in North Dakota completed during the first half of 2021, increased completions activity in North Dakota and the Marcellus, and strong well performance. These increases were partially offset by the impact of severe winter weather in North Dakota in April and December 2022, the Canadian asset divestments completed during the fourth quarter of 2022, and the Sleeping Giant and Russian Creek divestment completed during the fourth quarter of 2021.

● Full year 2022 net income was $914.3 million, or $3.91 per share, compared to net income of $234.4 million, or $0.93 per share, in 2021. In 2022, adjusted net income¹ was $707.1 million, or $3.02 per share, compared to $315.7 million, or $1.25 per share, in 2021. The higher net income and adjusted net income was primarily due to higher commodity prices and production.

● Our realized 2022 Bakken crude oil price differential was $1.09/bbl above WTI, compared to $2.15/bbl below WTI in 2021. Bakken differentials strengthened throughout the year due to excess pipeline capacity in the region as regional production growth remained muted despite strong physical prices for crude oil delivered to the U.S. Gulf Coast. However, severe winter weather across the U.S. during the fourth quarter of 2022 resulted in reductions to refinery demand and basin-wide production curtailments that caused Bakken price differentials to weaken late in the year.

● Our 2022 Marcellus natural gas price differential was $0.72/Mcf below NYMEX, compared to $0.81/Mcf below NYMEX in 2021. The stronger pricing was driven by both inventory and supply concerns, particularly in Europe, given the reduction in natural gas supply from Russia for the upcoming winter, slightly offset by lower Northeast U.S. demand during the fall shoulder season.

● Operating expenses in 2022 were $9.99/BOE, compared to $8.69/BOE in 2021. The increase in operating expenses in 2022 was primarily due to the impact of contracts with price escalators linked to WTI and the Consumer Price Index, as well as increased well service activity and costs. Cash general and administrative (“G&A”) expenses in 2022 were $1.17/BOE, compared to $1.14/BOE in 2021.

● Capital spending totaled $432.0 million in 2022, in line with our guidance of $430 million.

● During 2022, a total of $452.5 million was returned to shareholders through share repurchases and dividends. In 2022, we repurchased 27.9 million shares at an average price of $14.71 per share for a total cost of $410.9 million and paid $41.6 million in dividends.

● We ended the year with net debt of $221.5 million, with $56.3 million drawn on our $900 million sustainability linked lending bank credit facility and were undrawn on our $365 million sustainability linked lending bank credit facility. At December 31, 2022, our net debt to adjusted funds flow ratio was 0.2x compared to 0.9x at December 31, 2021.

¹ This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in the following MD&A.

ENERPLUS 2022 FINANCIAL SUMMARY             3

YEAR END 2022 RESERVES SUMMARY

U.S. Standards¹ - after deduction of royalties (“net”), constant prices, U.S. dollars:

● Net total proved reserves were 322.3 MMBOE, a decrease of 5% year-over-year, with the reduction driven by the sale of substantially all of our Canadian assets in 2022. Excluding reserves changes due to the Canadian asset sales, net total proved reserves increased 2% year-over-year

● Enerplus added 40.8 MMBOE of net proved reserves in 2022 (including technical revisions and economic factors), replacing 112% of its 2022 net production

● Net proved developed producing (“PDP”) finding and development (“F&D”) costs were $8.27 per BOE

● Net proved F&D costs were $16.43 per BOE, including future development costs (“FDC”)

Canadian NI 51-101 Standards² - before deduction of royalties (“gross”), forecast prices, U.S. dollars:

● Gross proved plus probable (“2P”) reserves were 601.1 MMBOE, a decrease of 2% year-over-year, with the reduction driven by the sale of substantially all of our Canadian assets in 2022. Excluding reserves changes due to the Canadian asset sales, gross 2P reserves increased 3% year-over-year

● Enerplus added 63.3 MMBOE of gross 2P reserves in 2022 (including technical revisions and economic factors), replacing 139% of its 2022 gross production

● Gross PDP F&D costs were $7.15 per BOE

● Gross 2P F&D costs were $17.82 per BOE, including FDC

¹ See “Presentation of Reserves Information” section in the following MD&A for definition of U.S. Standards.

² See “Basis of Presentation” section in the following MD&A for definition of Canadian NI 51-101 Standards.

4ENERPLUS 2022 FINANCIAL SUMMARY

       MD&A

Exhibit 99.3

Management’s Discussion and Analysis (“MD&A”)

The following discussion and analysis of financial results is dated February 23, 2023 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, 2022 and 2021 and for the years ended December 31, 2022, 2021 and 2020.

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 and Other Financial Measures” at the end of this MD&A for further information.

BASIS OF PRESENTATION

The Financial Statements and notes thereto have been prepared in accordance with U.S. GAAP. Unless otherwise stated, all dollar amounts are presented in U.S. dollars. Certain prior period amounts have been restated to conform with current period presentation as a result of the voluntary and retroactively applied change in the presentation currency from Canadian to U.S. dollars adopted by the Company in the fourth quarter of 2021.

Subsequent to the year ended December 31, 2022, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars effective January 1, 2023. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a prospective change in functional currency of the parent entity to U.S. dollars, consistent with the functional currency of its U.S. subsidiary.

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.

In accordance with U.S. GAAP, crude oil and natural gas sales are presented net of royalties in the Financial Statements. In addition, unless otherwise noted, all production volumes are presented on a “net” basis (after deduction of royalty obligations plus the Company’s royalty interests) consistent with U.S. oil and gas reporting standards. All reserves information in this MD&A has been prepared in accordance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“Canadian NI 51-101 Standards”). Reserves information in this MD&A is presented in accordance with Canadian NI 51-101 Standards and also in accordance with oil and gas disclosure framework of the United States Securities and Exchange Commission (the “SEC”). See “Presentation of Reserves Information” section in this MD&A.

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.

ENERPLUS 2022 FINANCIAL SUMMARY             5

2022 FOURTH QUARTER OVERVIEW

Fourth quarter production averaged 106,915 BOE/day, in line with our fourth quarter production guidance range of 105,000 BOE/day – 110,000 BOE/day and a decrease compared to production of 107,808 BOE/day in the third quarter of 2022. Crude oil and natural gas liquids production averaged 65,356 bbls/day compared to the third quarter average of 68,382 bbls/day, in line with our fourth quarter liquids production guidance range of 64,000 bbls/day – 68,000 bbls/day. The decrease in fourth quarter production was primarily due to the impact of severe winter weather in December and the Canadian asset divestments. Our fourth quarter capital spending was $85.6 million, bringing total 2022 capital spending to $432 million, in line with our revised guidance of $430 million.

On October 31, 2022, the Company completed a disposition of certain Canadian assets for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. Total consideration was comprised of cash, common shares of the purchaser, and an amortizing interest-bearing secured loan provided by Enerplus. After purchase price adjustments and transaction costs, adjusted proceeds were $80.8 million.

On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. Total consideration was comprised of cash and common shares of the purchaser. After purchase price adjustments and transaction costs, adjusted proceeds were $132.2 million.

We reported net income of $330.7 million in the fourth quarter compared to net income of $305.9 million in the third quarter of 2022. The increase in net income was primarily the result of a $151.9 million gain on the sale of Canadian assets, offset by lower production and realized prices.

Fourth quarter cash flow from operating activities and adjusted funds flow decreased to $316.6 million and $315.4 million respectively, from $409.9 million and $355.6 million, in the third quarter of 2022 due to lower production and realized prices, partially offset by a decrease in realized commodity derivative instrument losses.

Selected Fourth Quarter U.S and Canadian Financial Results

	Three months ended December 31, 2022							Three months ended December 31, 2021
($ millions, except per unit amounts)		U.S.		Canada		Total			U.S.		Canada		Total
Average Daily Production Volumes
Light and medium oil (bbls/day)			—		1,512		1,512		—		2,185		2,185
Heavy oil (bbls/day)			—		1,668		1,668		—		3,224		3,224
Tight oil (bbls/day)			51,421		—		51,421		50,010		—		50,010
Total crude oil (bbls/day)			51,421		3,180		54,601		50,010		5,409		55,419
Natural gas liquids (bbls/day)			10,679		76		10,755		9,236		304		9,540
Conventional natural gas (Mcf/day)			—		2,323		2,323		—		7,997		7,997
Shale gas (Mcf/day)			246,917		111		247,028		218,952		237		219,189
Total natural gas (Mcf/day)			246,917		2,434		249,351		218,952		8,234		227,186
Total average daily production (BOE/day)			103,253		3,662		106,915		95,738		7,085		102,823
Pricing(1)
Crude oil (per bbl)		$	84.27	$	63.58	$	83.06	$	76.49	$	63.39	$	75.21
Natural gas liquids (per bbl)			21.73		43.56		21.88		38.56		45.06		38.77
Natural gas (per Mcf)			4.76		4.75		4.76		3.90		4.53		3.92
Property, Plant and Equipment
Capital and office expenditures		$	84.6	$	1.7	$	86.3	$	77.6	$	4.0	$	81.6
Property and land acquisitions			2.7		0.1		2.9		2.1		0.6		2.7
Property and land divestments			1.0		(213.0)		(212.0)		(108.0)		(0.9)		(108.9)
Netback Before Impact of Commodity Derivative Contracts(2)
Crude oil and natural gas sales		$	528.6	$	20.1	$	548.7	$	463.2	$	36.4	$	499.6
Operating expenses			(89.4)		(5.8)		(95.2)		(69.2)		(10.8)		(80.0)
Transportation costs			(38.6)		(1.1)		(39.7)		(39.1)		(1.3)		(40.4)
Production taxes			(39.1)		(0.5)		(39.6)		(32.3)		(0.5)		(32.8)
Netback before impact of commodity derivative contracts		$	361.5	$	12.7	$	374.2	$	322.6	$	23.8	$	346.4

(1) Before transportation costs and the effects of commodity derivative instruments.

(2) This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

6ENERPLUS 2022 FINANCIAL SUMMARY

Comparing the fourth quarter of 2022 with the same period in 2021:

● Average daily production was 106,915 BOE/day, an increase of 4% from 102,823 BOE/day in the fourth quarter of 2021. The increase in crude oil and natural gas production was due to strong well performance and increased completions activity in North Dakota and the Marcellus during 2022, partially offset by the impact of severe winter weather in North Dakota in December, and the Canadian asset divestments completed during the fourth quarter of 2022.

● Our crude oil and natural gas liquids production accounted for 61% of our total production mix in the fourth quarter of 2022, compared to 63% in 2021.

● Capital spending increased to $85.6 million compared to $81.1 million in the fourth quarter of 2021, with the majority of the spending focused on our U.S. crude oil properties, including the drilling and completion of 10 net wells.

● Operating expenses were $95.2 million or $9.68/BOE compared to $80.0 million or $8.46/BOE in the fourth quarter of 2021. The increase was primarily due to the impact of contracts with price escalators linked to WTI and the Consumer Price Index, as well as increased well service activity and costs.

● Cash G&A expenses increased to $11.3 million, compared to $10.6 million in 2021, and increased on a per BOE basis to $1.15/BOE in the fourth quarter of 2022, compared to $1.12/BOE in the same period of 2021, due to inflationary pressure on labour and services.

● During the fourth quarter of 2022, our Bakken crude oil price differential averaged $1.05/bbl above WTI, compared to $0.88/bbl below WTI for the same period in 2021. Bakken crude oil price differentials continued to trade above WTI due to excess pipeline capacity in the region, as well as continued demand for crude oil delivered to the U.S. Gulf Coast region.

● Our fourth quarter 2022 Marcellus natural gas differential was $1.18/Mcf below NYMEX, compared to $1.70/Mcf below NYMEX during the same period in 2021. Our Marcellus differential narrowed due to stronger regional prices as we entered the winter season.

● We reported net income of $330.7 million in the fourth quarter of 2022 compared to $176.9 million in the fourth quarter of 2021. Net income increased due to a $151.9 million gain on the sale of the remaining Canadian assets as well as increased production in the Bakken and Marcellus, and stronger commodity prices.

● Cash flow from operating activities and adjusted funds flow increased to $316.6 million and $315.4 million, respectively, in the fourth quarter of 2022, compared to $283.5 million and $258.5 million in the fourth quarter of 2021. This was due to increased production in the Bakken and Marcellus and higher realized prices.

● During the fourth quarter of 2022, we repurchased and cancelled 9,798,752 common shares under a normal course issuer bid (“NCIB”) at an average price of $17.24 per common share. During the fourth quarter of 2021, we repurchased and cancelled 11,240,071 common shares under the NCIB at an average price of $10.08 per common share.

● During the fourth quarter of 2022, the Board of Directors approved a 10% increase to the quarterly dividend to $0.055 per share, from $0.050 per share.

● Net debt to adjusted funds flow was 0.2x at December 31, 2022 compared to 0.9x at December 31, 2021.

ENERPLUS 2022 FINANCIAL SUMMARY             7

2022 OVERVIEW AND 2023 OUTLOOK

Summary of Guidance and Results	Revised 2022 Guidance	2022 Results	2023 Guidance
Capital spending ($ millions)	$430	$432	$500 - $550
Average annual production (BOE/day)	99,750 - 101,000	100,326	93,000 - 98,000
Average annual crude oil and natural gas liquids production (bbls/day)	61,500 - 62,500	61,698	57,000 - 61,000
Fourth quarter average production (BOE/day)	105,000 - 110,000	106,915	—
Fourth quarter average crude oil and natural gas liquids production (bbls/day)	64,000 - 68,000	65,356	—
Average production tax rate (% of gross sales, before transportation)	7%	7%	7%
Operating expenses (per BOE)	$10.00	$9.99	$10.75 - $11.75
Transportation costs (per BOE)	$4.25	$4.22	$4.35
Cash G&A expenses (per BOE)	$1.20	$1.17	$1.35
Current tax expense (% of adjusted funds flow before tax)	2% - 3%	2%	5% - 6%
Differential/Basis Outlook and Results(1)
Average U.S. Bakken crude oil differential (compared to WTI crude oil)	$1.25/bbl	$1.09/bbl	$0.75/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)	$(0.75)/Mcf	$(0.72)/Mcf	($0.75)/Mcf

(1) Excludes transportation costs.

2022 OVERVIEW

Our 2022 annual average production was 100,326 BOE/day with crude oil and natural gas liquids volumes of 61,698 bbls/day, consistent with our revised production guidance target of 99,750 BOE/day – 101,000 BOE/day and revised crude oil and natural gas liquids production guidance of 61,500 bbls/day – 62,500 bbls/day. Our capital spending for the year totaled $432 million, in line with our revised guidance of $430 million. The majority of our capital was directed to our U.S. crude oil properties, with approximately 86% of total spending focused on our North Dakota properties. The success of our capital program delivered crude oil and natural gas liquids production growth of 10% and overall production growth of 9% compared to 2021.

During 2022, a total of $452.5 million, representing 57% of free cash flow¹, was returned to shareholders through share repurchases and dividends compared to $153.7 million in 2021. In 2022, we repurchased 11% of our outstanding common shares at an average price of $14.71 per common share. During 2022, we increased our quarterly dividend three times resulting in a 67% increase to $0.055 per common share, and paid a total of $41.6 million (December 31, 2021 - $30.5 million).

On October 31, 2022, the Company completed a disposition of certain Canadian assets for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. Total consideration was comprised of cash, common shares of the purchaser, and an amortizing interest-bearing secured loan provided by Enerplus. After purchase price adjustments and transaction costs, adjusted proceeds were $80.8 million.

On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. Total consideration was comprised of cash and common shares of the purchaser. After purchase price adjustments and transaction costs, adjusted proceeds were $132.2 million. The two divestments resulted in the recognition of a $151.9 million asset divestment gain in net income during 2022.

Our Bakken sales price differentials averaged $1.09/bbl above WTI, below our revised guidance of $1.25/bbl above WTI. Bakken differentials strengthened throughout the year due to excess pipeline capacity in the region as regional production growth remained muted despite strong physical prices for crude oil delivered to the U.S. Gulf Coast. However, severe winter weather across the U.S. during the fourth quarter of 2022 resulted in reductions to refinery demand and basin-wide production curtailments that caused Bakken price differentials to weaken late in the year. Our Marcellus differential of $0.72/Mcf below NYMEX was in line with our differential guidance of $0.75/Mcf below NYMEX.

Operating expenses were $9.99/BOE, in line with our revised guidance of $10.00/BOE and representing a 15% increase from the prior year. The increase was due to contracts with price escalators linked to WTI crude oil prices and the Consumer Price Index, as well as increased well service activity and costs. Cash G&A expenses were $1.17/BOE, lower than our revised guidance of $1.20/BOE.

Cash flow from operations and adjusted funds flow increased to $1,173.4 million and $1,230.3 million, respectively, from $604.8 million and $712.4 million in 2021. The increase was due to an increase in crude oil and natural gas sales as a result of our capital program and increased commodity prices.

¹ This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

8ENERPLUS 2022 FINANCIAL SUMMARY

We reported net income of $914.3 million in 2022, compared to net income of $234.4 million in 2021. The increase in net income was due to an increase in production, stronger commodity prices, a decrease in commodity derivative instrument losses, and a $151.9 million gain on the sale of Canadian assets, partially offset by higher income tax expense in 2022.

At December 31, 2022, net debt was $221.5 million and our net debt to adjusted funds flow ratio decreased to 0.2x in 2022 from 0.9x in 2021. During the fourth quarter of 2022, Enerplus converted its $400 million revolving bank credit facility to a $365 million sustainability linked lending (“SLL”) bank credit facility and extended the maturity to October 31, 2025. The $365 million SLL bank credit facility has the same targets as Enerplus’ $900 million SLL bank credit facility (together referred to as the “Bank Credit Facilities”), which was renewed with $50 million maturing on October 31, 2025, and $850 million maturing on October 31, 2026. There were no other significant amendments or additions to the two agreements’ terms or covenants.

2023 OUTLOOK

In 2023, we plan to continue to focus on creating value for shareholders through sustainable crude oil and natural gas liquids production growth. The 2023 capital budget is expected to deliver robust free cash flow. We expect our capital spending for 2023 to range between $500 - $550 million, with the majority directed to our North Dakota assets.

Annual average production is expected to be 93,000 BOE/day - 98,000 BOE/day, including 57,000 bbls/day - 61,000 bbls/day of crude oil and natural gas liquids production.

We expect our Bakken sales price differential to average $0.75/bbl above WTI in 2023. In the Marcellus, we have a differential outlook of $0.75/Mcf below NYMEX in 2023.  

We expect operating expenses to average between $10.75/BOE - $11.75/BOE and cash G&A expenses to average $1.35/BOE during 2023. We also expect 2023 cash tax of approximately 5 - 6% of adjusted funds flow before tax assuming WTI of $80.00/bbl and NYMEX of $3.50/Mcf.

We plan to continue to return at least 60% of free cash flow¹ to our shareholders in 2023 through share repurchases and dividends, based on current market conditions. Remaining free cash flow not allocated to return of capital is expected to be directed to reinforcing the balance sheet. We intend to renew the NCIB in August 2023. Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share to be paid in March 2023. We expect to fund the dividend through the free cash flow generated by the business.

¹ This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

ENERPLUS 2022 FINANCIAL SUMMARY             9

RESULTS OF OPERATIONS

Production

Average Daily Production Volumes	2022	2021	2020
Light and medium oil (bbls/day)	1,950	2,231	2,601
Heavy oil (bbls/day)	2,556	3,302	3,424
Tight oil (bbls/day)	47,511	42,981	30,656
Total crude oil (bbls/day)	52,017	48,514	36,681
Natural gas liquids (bbls/day)	9,681	7,823	4,499
Conventional natural gas (Mcf/day)	5,925	7,818	11,416
Shale gas (Mcf/day)	225,845	207,486	179,598
Total natural gas (Mcf/day)	231,770	215,304	191,014
Total daily sales (BOE/day)	100,326	92,221	73,016

Production in 2022 averaged 100,326 BOE/day, in line with our revised production guidance range of 99,750 BOE/day - 101,000 BOE/day, and resulted in a 9% increase compared to 2021 production of 92,221 BOE/day. Crude oil and natural gas liquids production in 2022 averaged 61,698 bbls/day, in line with our revised guidance range of 61,500 bbls/day - 62,500 bbls/day. Compared to 2021, our crude oil and natural gas liquids production increased 10% due to the impact of 44 net wells coming onstream in North Dakota during 2022. Additionally, there was a full year of production from the acquisition of Bruin E&P Holdco, LLC (the “Bruin Acquisition”) and certain assets in the Williston Basin from Hess Bakken Investment II, LLC (the “Dunn County Acquisition”), which were acquired in the first half of 2021. These increases were partially offset by the impact of severe winter weather in North Dakota in April and December 2022, the sale of our interests in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, which closed during the fourth quarter of 2021, and the sale of substantially all of our Canadian assets in the fourth quarter of 2022.

Our U.S. production volumes increased by 11% compared to 2021 and our U.S. crude oil and natural gas liquids production increased by 13% to 56,950 bbls/day, due to higher completions activity, and a full year of production from the Bruin and Dunn County assets in 2022, compared to 2021. Natural gas production in the Marcellus increased by 7% to 28,158 BOE/day in 2022, compared to 26,324 BOE/day in 2021, due to new wells coming on-stream in 2022.

Canadian production volumes decreased by 20% compared to the prior year, due to the closing of the sale of substantially all of our remaining Canadian assets to two separate purchasers during the fourth quarter of 2022. Combined production from the two divestments was 6,400 BOE/day. We expect no Canadian production in 2023.

Our crude oil and natural gas liquids production accounted for 61% of our total average daily production in 2022, consistent with 61% in 2021.

Production for 2021 increased by 26%, compared to 2020, largely due to production from the Bruin and Dunn County assets acquired in the first half of 2021 and the impact of 43 net wells coming onstream in North Dakota during 2021. Production in 2020 was impacted by temporary curtailments 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 as a result of the COVID-19 pandemic.  

2023 Guidance

We expect annual average production for 2023 of 93,000 BOE/day - 98,000 BOE/day, including 57,000 bbls/day - 61,000 bbls/day of crude oil and natural gas liquids production.

10ENERPLUS 2022 FINANCIAL SUMMARY

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)	2022		2021		2020
Benchmarks
WTI crude oil ($/bbl)	$	94.23	$	67.92	$	39.40
Brent (ICE) crude oil ($/bbl)		98.89		70.79		43.21
Propane – Conway ($/bbl)		46.03		43.74		18.59
NYMEX natural gas – last day ($/Mcf)		6.64		3.84		2.08
CDN/US average exchange rate		0.77		0.80		0.75
CDN/US period end exchange rate		0.74		0.79		0.79
Enerplus selling price(1)
Crude oil ($/bbl)	$	93.63	$	65.89	$	33.30
Natural gas liquids ($/bbl)		30.70		29.51		7.79
Natural gas ($/Mcf)		5.51		2.94		1.40
Average benchmark differentials
Bakken DAPL - WTI ($/bbl)	$	2.62	$	(0.79)	$	(4.27)
Brent (ICE) - WTI ($/bbl)		4.66		2.87		3.81
MSW Edmonton – WTI ($/bbl)		(1.81)		(3.88)		(5.33)
WCS Hardisty – WTI ($/bbl)		(18.28)		(13.04)		(12.60)
Transco Leidy monthly – NYMEX ($/Mcf)		(1.04)		(0.94)		(0.72)
Transco Z6 Non-New York monthly – NYMEX ($/Mcf)		(0.12)		(0.36)		(0.34)
Enerplus realized differentials(1)(2)
Bakken crude oil – WTI ($/bbl)	$	1.09	$	(2.15)	$	(5.39)
Marcellus natural gas – NYMEX ($/Mcf)		(0.72)		(0.81)		(0.65)
Canada crude oil – WTI ($/bbl)		(15.80)		(12.94)		(13.22)

(1) Excluding transportation costs 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 $94.23/bbl in 2022, a 39% increase from 2021. The Russian invasion of Ukraine and the consequential impact on global oil supply resulted in crude oil prices trading above $120/bbl during the second quarter of 2022. Prices moderated during the second half of 2022 driven mainly by concerns over a global recession as central banks aggressively raised key interest rates in response to year-over-year inflation. North American oil supply growth remained moderate as the industry continued its capital discipline while focusing on shareholder returns. In addition, global inventory balances remain tight, supported by the policy of the Organization of the Petroleum Exporting Countries Plus (“OPEC+”) to maintain certain levels of production curtailments to provide support and stability to global oil markets.

Our 2022 realized crude oil price averaged $93.63/bbl, representing a 42% increase compared to 2021, which reflects the improvement in WTI pricing as well as stronger sales price differentials for our Bakken crude oil production.

Our Bakken sales price differentials improved by $3.24/bbl in 2022 compared to 2021, averaging $1.09/bbl above WTI. Bakken differentials strengthened throughout the year due to excess pipeline capacity in the region as regional production growth remained muted despite strong physical prices for crude oil delivered to the U.S. Gulf Coast. However, severe winter weather across the U.S. during the fourth quarter of 2022 resulted in reductions to refinery demand and basin-wide production curtailments that caused Bakken price differentials to weaken late in the year. The outlook for Bakken production growth continues to be relatively modest and as such we expect differentials to remain supportive given the excess pipeline capacity out of the basin. For 2023 we expect our realized Bakken differential to average $0.75/bbl above WTI.

Canadian crude oil differentials weakened in 2022 compared to the prior year, particularly in the second half of 2022. Heavy differentials traded at wider discounts due in part to production growth, with Canadian production reaching records levels in the fourth quarter of 2022. An unplanned outage on TC Energy’s Keystone Pipeline system and increasing apportionment levels on the Enbridge Mainline added further pressure on Canadian crude oil differentials.

ENERPLUS 2022 FINANCIAL SUMMARY             11

We realized an average price of $30.70/bbl on our natural gas liquids production in 2022, a 4% increase compared to 2021. North American natural gas liquids pricing increased in the first quarter of 2022 in part due to the strength in overall commodity prices caused by the Russian invasion of Ukraine. Natural gas liquids benchmark prices declined during the second half of the year due to growing concerns around global recession risk, industrial demand for petrochemical feedstocks and inventory accumulations.

Monthly Crude Oil Prices

NATURAL GAS

Our realized natural gas price averaged $5.51/Mcf in 2022, an 87% increase from 2021. Our realized price increased more than the NYMEX natural gas benchmark price due to strength in regional natural gas prices in the Northeast U.S.

In the Marcellus, we realized an average sales price differential of $0.72/Mcf below NYMEX which was narrower than our 2021 realized sales price differential of $0.81/Mcf. NYMEX natural gas prices at Henry Hub settled higher during this period due to both inventory and supply concerns, particularly in Europe, given the reduction in natural gas supply from Russia for the upcoming winter. Transco Z6 Non-New York monthly benchmark differentials averaged $0.12/Mcf below NYMEX for 2022, $0.24/Mcf narrower versus 2021. The Transco Leidy monthly benchmark differential averaged $1.04/Mcf below NYMEX for 2022, which was wider than 2021 due to lower Northeast U.S. demand during the fall shoulder season. For 2023, we expect our Marcellus differential to average $0.75/Mcf below NYMEX.

12ENERPLUS 2022 FINANCIAL SUMMARY

Monthly Natural Gas Prices

FOREIGN EXCHANGE

Fluctuations in the CDN/US dollar exchange rate impacts the amount of our Canadian dollar denominated costs such as G&A expenses and dividends paid to Canadian residents. The U.S. dollar strengthened compared to the Canadian dollar during 2022 as a result of the Russian invasion of Ukraine and concerns over a global recession. The exchange rate averaged $0.77 CDN/US in 2022, compared to $0.80 CDN/US during 2021, and ended the year at $0.74 CDN/US in 2022.

Monthly CDN/US 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.

We expect our commodity derivative contracts to protect a portion of our cash flow from operating activities and adjusted funds flow. As of February 22, 2023, we have 15,000 bbls/day hedged for first half of 2023 and 5,000 bbls/day hedged for the second half of 2023. We have also hedged 120,000 Mcf/day for the period from January 1, 2023 to March 31, 2023 and 50,000 Mcf/day for the period from April 1, 2023 to October 31, 2023. Our crude oil contracts consist mainly of three-way collars, which limits upward price participation to the call strike level. Additionally, the sold put limits the amount of downside protection we have to the difference between the strike price of the purchased and sold puts.

ENERPLUS 2022 FINANCIAL SUMMARY             13

The following is a summary of Enerplus’ financial contracts in place at February 22, 2023:

	WTI Crude Oil ($/bbl)(1)(2)		NYMEX Natural Gas ($/Mcf)(2)
	Jan 1, 2023 –	Jul 1, 2023 –	Jan 1, 2023 –	Apr 1, 2023 –
	Jun 30, 2023	Dec 31, 2023	Mar 31, 2023	Oct 31, 2023
Swaps
Volume (bbls/day)	10,000	10,000	–	–
Brent - WTI Spread	$ 5.47	$ 5.47	–	–
3 Way Collars
Volume (bbls/day)	15,000	5,000	–	–
Sold Puts	$ 61.67	$ 65.00	–	–
Purchased Puts	$ 79.33	$ 85.00	–	–
Sold Calls	$ 114.31	$ 128.16	–	–
Collars
Volume (Mcf/day)	–	–	120,000	50,000
Volume (bbls/day)(3)	2,000	2,000	–	–
Purchased Puts	$ 5.00	$ 5.00	$ 6.27	$ 4.05
Sold Calls	$ 75.00	$ 75.00	$ 18.17	$ 7.00

(1) The total average deferred premium spent on our outstanding crude oil contracts is $1.25/bbl from January 1, 2023 – December 31, 2023.

(2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes.

(3) Outstanding commodity derivative instruments acquired as part of the Bruin Acquisition.

ACCOUNTING FOR PRICE RISK MANAGEMENT

Commodity Risk Management Gains/(Losses)
($ millions)	2022		2021		2020
Realized gains/(losses):
Crude oil	$	(275.7)	$	(146.3)	$	92.8
Natural gas		(71.5)		(16.7)		—
Total realized gains/(losses)	$	(347.2)	$	(163.0)	$	92.8
Unrealized gains/(losses):
Crude oil	$	125.8	$	(111.6)	$	(19.9)
Natural gas		23.7		0.2		2.8
Total unrealized gains/(losses)	$	149.5	$	(111.4)	$	(17.1)
Total commodity derivative instruments gains/(losses)	$	(197.7)	$	(274.4)	$	75.7

(Per BOE)	2022		2021		2020
Total realized gains/(losses)	$	(9.48)	$	(4.84)	$	3.47
Total unrealized gains/(losses)		4.08		(3.31)		(0.64)
Total commodity derivative instruments gains/(losses)	$	(5.40)	$	(8.15)	$	2.83

During 2022, Enerplus realized losses of $275.7 million on crude oil contracts and $71.5 million on our natural gas contracts, compared to realized losses of $146.3 million on crude oil contracts and $16.7 million on our natural gas contracts in 2021. Realized losses in 2022 on crude oil and natural gas contracts were due to commodity prices exceeding the swap and sold call values on our commodity derivative contracts.

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 an unrealized loss or gain to earnings. At December 31, 2022, the fair value of our crude oil contracts was in a net liability position of $0.6 million (December 31, 2021 – net liability position of $146.7 million). The fair value of our natural gas contracts at December 31, 2022 was in a net asset position of $26.7 million (December 31, 2021 – net asset position of $3.0 million). The change in fair value of our crude oil and natural gas contracts represented unrealized gains of $125.8 million and unrealized gains of $23.7 million, respectively, during 2022 and unrealized losses of $111.6 million and unrealized gains of $0.2 million, respectively, during 2021.

14ENERPLUS 2022 FINANCIAL SUMMARY

Crude oil and natural gas sales

($ millions)	2022		2021		2020
Crude oil and natural gas sales	$	2,353.4	$	1,482.6	$	553.7
Per BOE	$	64.27	$	44.04	$	20.72

Crude oil and natural gas sales for 2022 totaled $2,353.4 million, or $64.27/BOE, an increase of 59% from $1,482.6 million, or $44.04/BOE in 2021. The increase in revenue is a result of increased production volumes from our capital program and higher commodity prices. Refer to the “Pricing” section for further details in this MD&A.

Comparing 2021 to 2020, crude oil and natural gas sales increased 168% to $1,482.6 million, or $44.04/BOE, from $553.7 million, or $20.72/BOE, as a result of increased production volumes, including the combined impact of the Bruin and Dunn County acquisitions in 2021, as well as higher commodity prices.

Operating Expenses

($ millions, except per BOE amounts)	2022		2021		2020
Operating expenses	$	365.7	$	292.4	$	197.1
Per BOE	$	9.99	$	8.69	$	7.38

Operating expenses for 2022 were $365.7 million or $9.99/BOE, in line with our revised guidance of $10.00/BOE and an increase of $73.3 million or $1.30/BOE from 2021. The increase was primarily due to the impact of contracts with price escalators linked to WTI crude oil prices and the Consumer Price Index, as well as increased well service activity and costs.

Operating expenses for 2021 were $292.4 million or $8.69/BOE, representing an increase of $95.3 million or $1.31/BOE from 2020. The increase was primarily due to higher U.S. crude oil production as a result of the Bruin and Dunn County acquisitions and increased liquids weighting. In addition, operating expenses increased due to higher well service activity in the second half of 2021 and higher water handling charges as a result of contracts with price escalators linked to WTI crude oil prices, which were triggered in 2021.

2023 Guidance

We expect operating expenses of between $10.75/BOE - $11.75/BOE for 2023, an increase from 2022 due to inflation adjusted contract prices and general cost escalation, increased gas processing due to improved gas capture rates, and higher well service activity.

Transportation Costs

($ millions, except per BOE amounts)	2022		2021		2020
Transportation costs	$	154.7	$	128.3	$	98.7
Per BOE	$	4.22	$	3.81	$	3.69

Transportation costs in 2022 were lower than our revised guidance of $4.25/BOE, averaging $4.22/BOE or $154.7 million, compared to $3.81/BOE or $128.3 million in 2021. The increase in transportation costs was primarily a result of increased U.S. production with higher associated transportation costs and additional firm transportation commitments on the Dakota Access Pipeline (“DAPL”) as a result of the Bruin Acquisition and participation in the DAPL expansion in August 2021.

Transportation costs in 2021 increased to $3.81/BOE compared to $3.69/BOE in 2020. The increase in transportation costs was primarily a result of increased U.S. production with higher associated transportation costs and additional firm transportation commitments compared to the prior year.

2023 Guidance

We expect an increase in transportation expenses to $4.35/BOE for 2023 due to the impact of contracts with price escalators  linked to the Consumer Price Index and an expected increase in U.S. production.

ENERPLUS 2022 FINANCIAL SUMMARY             15

Production Taxes

($ millions, except per BOE amounts)	2022		2021		2020
Production taxes	$	167.0	$	102.0	$	37.4
Per BOE	$	4.56	$	3.03	$	1.40
Production taxes (% of crude oil and natural gas sales)		7.1%		6.9%		6.8%

Production taxes include state production taxes, Pennsylvania impact fees and Canadian freehold mineral taxes.

Production taxes were in line with our revised guidance of 7.0% for 2022, averaging 7.1% of crude oil and natural gas sales, before transportation. Production taxes of $167.0 million in 2022 increased in comparison to prior years due to higher realized commodity prices and production volumes. Production taxes of $102.0 million in 2021 were higher in comparison to 2020, due to higher realized commodity prices and production volumes.

2023 Guidance

We expect annual production taxes to average 7% in 2023.

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, 2022
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			71,271 BOE/day		174,330 Mcfe/day		100,326 BOE/day
Netback $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	75.98	$	5.92	$	64.27
Operating expenses			(13.57)		(0.20)		(9.99)
Transportation costs			(3.76)		(0.89)		(4.22)
Production taxes			(6.30)		(0.05)		(4.56)
Netback before impact of commodity derivative contracts		$	52.35	$	4.78	$	45.50
Realized hedging gains/(losses)			(10.60)		(1.12)		(9.48)
Netback after impact of commodity derivative contracts		$	41.75	$	3.66	$	36.02
Netback before impact of commodity derivative contracts(1) ($ millions)		$	1,361.8	$	304.2	$	1,666.0
Netback after impact of commodity derivative contracts(1) ($ millions)		$	1,086.1	$	232.9	$	1,318.8

(1) This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

16ENERPLUS 2022 FINANCIAL SUMMARY

	Year ended December 31, 2021
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			64,479 BOE/day		166,454 Mcfe/day		92,221 BOE/day
Netback $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	54.91	$	3.13	$	44.04
Operating expenses			(11.89)		(0.21)		(8.69)
Transportation costs			(3.11)		(0.91)		(3.81)
Production taxes			(4.23)		(0.04)		(3.03)
Netback before impact of commodity derivative contracts		$	35.68	$	1.97	$	28.51
Realized hedging gains/(losses)			(6.22)		(0.28)		(4.84)
Netback after impact of commodity derivative contracts		$	29.46	$	1.69	$	23.67
Netback before impact of commodity derivative contracts(1) ($ millions)		$	840.0	$	119.9	$	959.9
Netback after impact of commodity derivative contracts(1) ($ millions)		$	693.7	$	103.2	$	796.9

(1) This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

	Year ended December 31, 2020
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			45,277 BOE/day		166,434 Mcfe/day		73,016 BOE/day
Netback $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Crude oil and natural gas sales		$	27.81	$	1.52	$	20.72
Operating expenses			(10.91)		(0.27)		(7.38)
Transportation costs			(2.67)		(0.89)		(3.69)
Production taxes			(2.18)		(0.02)		(1.40)
Netback before impact of commodity derivative contracts		$	12.05	$	0.34	$	8.25
Realized hedging gains/(losses)			5.60		—		3.47
Netback after impact of commodity derivative contracts		$	17.65	$	0.34	$	11.72
Netback before impact of commodity derivative contracts(1) ($ millions)		$	199.7	$	20.8	$	220.5
Netback after impact of commodity derivative contracts(1) ($ millions)		$	292.6	$	20.8	$	313.4

(1) This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

As a result of the strong commodity price environment for both crude oil and natural gas, our netback before the impact of commodity derivative contracts¹ increased by 74% in 2022 compared to 2021, and our netback after the impact of commodity derivative contracts¹ increased by 65%. During 2022, our crude oil properties accounted for 82% of our netback before impact of commodity derivative contracts¹ and 82% of our netback after the impact of commodity derivative contracts¹, compared to 88% and 87%, respectively, in 2021.

¹ This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

ENERPLUS 2022 FINANCIAL SUMMARY             17

General and Administrative (“G&A”) 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”).

($ millions)	2022		2021		2020
Cash:
G&A expense	$	42.8	$	38.4	$	33.5
Share-based compensation expense		5.7		6.9		(0.9)
Non-Cash:
Share-based compensation expense		22.9		13.8		9.7
Equity swap loss/(gain)		(1.0)		(1.9)		1.0
G&A expense/(recovery)		(0.4)		(0.4)		(0.2)
Total G&A expenses	$	70.0	$	56.8	$	43.1

(Per BOE)	2022		2021		2020
Cash:
G&A expense	$	1.17	$	1.14	$	1.26
Share-based compensation expense		0.16		0.20		(0.04)
Non-Cash:
Share-based compensation expense		0.63		0.41		0.36
Equity swap loss/(gain)		(0.03)		(0.06)		0.04
G&A expense/(recovery)		(0.01)		(0.01)		(0.01)
Total G&A expenses	$	1.92	$	1.68	$	1.61

Cash G&A expenses were $42.8 million or $1.17/BOE in 2022, lower than our revised guidance of $1.20/BOE. Total cash G&A expenses increased due to inflationary pressure on labour and services, compared to 2021. Total cash G&A expenses were lower during 2020 due to a combination of salary reductions as well as COVID-19 pandemic government funding.

SBC can be equity settled or cash-settled, depending on the underlying plan to which it relates. Cash-settled SBC expense was $5.7 million or $0.16/BOE in 2022, compared to $6.9 million or $0.20/BOE in 2021, and relates to our director plans. The lower expense was due to fewer cash-settled units outstanding in 2022 compared to 2021, partially offset by an increase in share price. During 2020, we reported a cash SBC recovery due to a decrease in our share price during the year.  

Equity settled non-cash SBC was $22.9 million or $0.63/BOE in 2022, compared to $13.8 million or $0.41/BOE in 2021 and $9.7 million or $0.36/BOE in 2020. Performance Share Units (“PSUs”), as one of the equity settled LTI plans, is impacted by performance multipliers. During 2022, the multipliers were higher than in 2021 resulting in increased expense. The equity settled non-cash SBC was lower in 2020, due to lower multipliers.  

Enerplus previously had hedged a portion of the outstanding cash-settled units under our LTI plans. During 2022, we recorded an unrealized mark-to-market gain of $1.0 million on these equity derivative contracts as a result of the improved share price (2021 – $1.9 million gain).Enerplus settled its equity derivative contracts during 2022 and did not have any equity derivatives outstanding at December 31, 2022

2023 Guidance

We expect cash G&A expenses of $1.35/BOE for 2023.

18ENERPLUS 2022 FINANCIAL SUMMARY

Interest Expense

Interest on our senior notes and Bank Credit Facilities for 2022 totaled $24.6 million, a decrease of 10% from $27.4 million in 2021. The decrease was primarily due to lower debt levels in 2022, compared to 2021, as a result of funding the 2021 Bruin and Dunn County acquisitions, offset by the impact of rising interest rates on our Bank Credit Facilities drawings in 2022. During 2022, we made our third principal payment out of five, and a bullet payment on our 2012 senior notes.  

In 2021, interest on our senior notes and Bank Credit Facilities of $27.4 million increased compared to $20.7 million in 2020 due to higher debt levels as a result of the Bruin and Dunn County acquisitions, partially offset by the final repayment of our 2009 senior notes and scheduled repayment of our 2012 senior notes, which carried higher interest rates than our Bank Credit Facilities.

At December 31, 2022, approximately 78% of our debt was based on fixed interest rates and 22% on floating interest rates (December 31, 2021 – 43%, 57%), with weighted average interest rates of 4.2% and 5.7%, respectively (December 31, 2021 – 4.2%, 1.9%).

Foreign Exchange

($ millions)	2022		2021		2020
Realized:
Foreign exchange (gain)/loss	$	(0.1)	$	3.5	$	0.8
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company		(0.9)		(2.3)		(0.9)
Unrealized:
Foreign exchange (gain)/loss on U.S. dollar working capital in parent company		11.2		(8.1)		1.3
Total foreign exchange (gain)/loss	$	10.2	$	(6.9)	$	1.2
CDN/US average exchange rate	$	0.77	$	0.80	$	0.75
CDN/US period end exchange rate	$	0.74	$	0.79	$	0.79

Enerplus recorded a total foreign exchange loss of $10.2 million in 2022, compared to a gain of $6.9 million in 2021 and a loss of $1.2 million in 2020. 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 working capital held in Canada at each period-end.

At December 31, 2022, $203.2 million of outstanding senior notes and $56.3 million drawn on the Bank Credit Facilities were designated as net investment hedges against the investment in our U.S. subsidiary. As a result, unrealized foreign exchange gains and losses on the translation of this U.S. dollar denominated debt are included in Other Comprehensive Income/(Loss). For the year ended December 31, 2022, Other Comprehensive Income/(Loss) included an unrealized loss of $26.5 million on our U.S. dollar denominated senior notes and Bank Credit Facilities (2021 – $4.1 million gain; 2020 – $1.8 million gain).

Property, Plant and Equipment

($ millions)	2022		2021		2020
Capital spending(1)	$	432.0	$	302.3	$	217.2
Office capital		1.3		1.6		2.2
Sub-total		433.3		303.9		219.4
Bruin Acquisition	$	—	$	520.2	$	—
Dunn County Acquisition		—		305.1		—
Canadian divestments(1)		(213.0)		—		—
Property and land acquisitions		22.5		9.8		7.5
Property and land divestments(1)		(18.4)		(112.7)		(4.5)
Sub-total		(208.9)		722.4		3.0
Total	$	224.4	$	1,026.3	$	222.4

(1) Excludes changes in non-cash investing working capital.

2022

Capital spending in 2022 totaled $432.0 million, in line with our revised guidance of $430 million. In 2022, we spent $368.0 million on our U.S. crude oil properties, and $57.6 million on our Marcellus natural gas assets. The increase in capital spending in 2022, compared to 2021, was due to increased capital activity on our North Dakota properties which includes properties from the 2021 Bruin and Dunn County acquisitions. Through our capital program, we added 63.3 MMBOE of gross proved plus probable Canadian NI 51-101 Standards reserves in 2022, replacing 139% of our production, including economic factors and technical revisions and before accounting for acquisitions and divestments.

ENERPLUS 2022 FINANCIAL SUMMARY             19

On October 31, 2022, the Company completed a disposition of certain Canadian assets for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. After purchase price adjustments, proceeds from the two divestments were $213.0 million with $61.7 million allocated to PP&E, excluding the reduced asset retirement obligation.

Property and land acquisitions in 2022 totaled $22.5 million, which included minor acquisitions of leases and undeveloped land. We recorded other property and land divestments of $18.4 million in 2022.

2021

Capital spending in 2021 totaled $302.3 million, including $256.1 million on our U.S. crude oil properties, $13.8 million on our Canadian crude oil properties and $31.0 million on our Marcellus natural gas assets. Through our capital program in 2021, we added 85.0 MMBOE of gross proved plus probable Canadian NI 51-101 Standards reserves, replacing 204% of our production, including economic factors and technical revisions and before accounting for acquisitions and divestments. Including acquired and divested volumes, we replaced 558% of our 2021 production adding 233.0 MMBOE of gross proved plus probable reserves.

During 2021, we completed the Bruin Acquisition for total cash consideration of $465.0 million or $420.2 million after purchase price adjustments, with $520.2 million allocated to PP&E, excluding the assumed asset retirement obligation. We also completed the Dunn County Acquisition for total cash consideration of $306.8 million, with $305.1 million allocated to PP&E, excluding the assumed asset retirement obligation.

Property divestments were related to the sale of our interest in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, during the fourth quarter of 2021 for total cash consideration of $115.0 million, before purchase price adjustments. After purchase price adjustments and transaction costs, adjusted proceeds of $107.8 million, were all allocated to PP&E, excluding the divested asset retirement obligation. Enerplus may receive up to $5.0 million in additional contingent payments if the WTI oil price averages over $65/bbl in 2022 and over $60/bbl in 2023. Subsequent to December 31, 2022, the Company received a $2.5 million contingent payment as a result of the WTI oil price exceeding $65/bbl in 2022.

2020

Capital spending in 2020 totaled $217.2 million, including $174.8 million on our U.S. crude oil properties, $17.4 million on our Canadian crude oil properties and $24.8 million on our Marcellus natural gas assets. Through our capital program in 2020, we added 16.7 MMBOE of gross proved plus probable Canadian NI 51-101 Standards reserves, replacing 50% of our net production, including economic factors and technical revisions and before accounting for acquisitions and divestments.

2023 Guidance

Our capital spending guidance range is $500 - $550 million for 2023.

Depletion, Depreciation and Accretion (“DD&A”)

($ millions, except per BOE amounts)	2022		2021		2020
DD&A expense	$	309.4	$	271.3	$	218.1
Per BOE	$	8.45	$	8.06	$	8.16

DD&A of PP&E is recognized using the unit of production method based on proved reserves. We recorded DD&A of $309.4 million, or $8.45/BOE, during 2022, an increase compared to $271.3 million, or $8.06/BOE, in 2021. The increase in total DD&A expense and per BOE is a result of higher overall production volumes, and higher PP&E costs from the Bruin and Dunn County acquisitions.

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 guidelines. 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.

20ENERPLUS 2022 FINANCIAL SUMMARY

Trailing twelve-month average crude oil and natural gas prices have improved throughout 2021 and 2022, after falling in 2020 as a result of the impacts of the COVID-19 pandemic. There were no impairments for the twelve months ended December 31, 2022. For the twelve months ended December 31, 2021, we recorded a PP&E impairment of $3.4 million related to our Canadian assets. For the twelve months ended December 31, 2020, we recorded a PP&E impairment of $751.7 million (Canadian cost centre: $100.9 million, U.S. cost centre: $650.8 million).

Enerplus requested and received a temporary exemption from the SEC to exclude the properties acquired in the Bruin Acquisition in the U.S. full cost ceiling test for the duration of 2021.

Many factors influence the allowed ceiling value compared to 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 and Deferred Tax Assets" 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, 2022, 2021 and 2020:

	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub			Exchange Rate
Year	$/bbl		CDN$/bbl		$/Mcf			$CDN/$US
2022	$	94.14	$	119.13	$	6.25	$	0.77
2021	$	66.55	$	78.15	$	3.64	$	0.80
2020	$	39.54	$	45.56	$	2.00	$	0.75

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 goodwill impairment of $149.2 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. At December 31, 2022 and 2021 there was no goodwill on our Condensed Consolidated Balance Sheet.

Asset Retirement Obligation (“ARO”)

In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets, such as surface leases, wells, facilities and pipelines. Total ARO included on our balance sheet is based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate, the timing of the costs to be incurred in future periods and estimates for inflation. We have estimated the net present value of our asset retirement obligation to be $114.7 million at December 31, 2022, compared to $132.8 million at December 31, 2021. The decrease in the net present value is largely due to the reduced liability in connection with the divestment of Canadian assets in 2022, offset by higher estimated costs due to high levels of inflation.

During 2022, we spent $17.4 million (2021 – $13.0 million, 2020 – $13.3 million) on our asset retirement obligations. The majority of our abandonment, reclamation and remediation costs are expected to be incurred between 2023 – 2034 and 2037 – 2053. 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 Facilities.

In 2022 and 2021, Enerplus benefited from provincial government assistance to support the cleanup of inactive or abandoned crude oil and natural gas wells. These programs provide funding directly to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. For twelve months ended December 31, 2022, Enerplus benefitted from $1.7 million (2021 – $4.6 million, 2020 – nil), in government assistance.

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 the remaining unamortized amount of our right to use an underlying asset for its remaining lease term. At December 31, 2022 our total lease liability was $22.9 million, compared to $28.9 million at December 31, 2021. At December 31, 2022 our ROU asset was $20.6 million, compared to $26.1 million at December 31, 2021.

ENERPLUS 2022 FINANCIAL SUMMARY             21

Income Taxes

($ millions)	2022		2021		2020
Current tax expense/(recovery)	$	28.1	$	2.7	$	(10.7)
Deferred tax expense/(recovery)		265.2		98.8		(188.3)
Total tax expense/(recovery)	$	293.3	$	101.5	$	(199.0)

In 2022, we recorded a current tax expense of $28.1 million or 2% of adjusted funds flow before tax in line with our revised guidance of 2-3% of adjusted funds flow before tax, compared to an expense of $2.7 million in 2021 and a recovery of $10.7 million in 2020. The increase in expense in 2022, compared to 2021, is due to additional U.S. federal and state tax resulting from higher net income for the year and the utilization of our net operating loss carryforward. The recovery in 2020 was related to the recognition of our final U.S. Alternative Minimum Tax ("AMT") refund.

In 2022, we recorded a deferred income tax expense of $265.2 million compared to an expense of $98.8 million in 2021 and a recovery of $188.3 million in 2020. The expense in 2022 and 2021 is primarily due to higher U.S. income. The deferred tax recovery in 2020 was due to net losses in 2020 from non-cash PP&E impairments in both the U.S. and Canada cost centres.

We assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not all or a portion of our deferred income tax assets will not be realized. We have considered available positive and negative evidence including future taxable income and reversing existing temporary differences in making this assessment. This assessment is primarily the result of projecting future taxable income using total proved and probable forecast average prices and costs. There is a risk of a valuation allowance in future periods if commodity prices weaken or other evidence indicates that some of our deferred income tax assets will not be realized. See “Risk Factors and Risk Management – Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets” in the Annual MD&A. For the year ended December 31, 2022, no valuation allowance was recorded against our Canadian income related deferred tax asset, however, a full valuation allowance has been recorded against our deferred income tax assets related to capital items. Our deferred income tax asset recorded in Canada is $155.0 million offset by a deferred income tax liability in the U.S. of $55.4 million as at December 31, 2022 (December 31, 2021 - $380.9 million net asset).

Our estimated tax pools at December 31, 2022 are as follows:

Pool Type ($ millions)	2022
U.S.
Depletable and depreciable assets	$	1,010
	$	1,010
Canada
Non-capital losses and other credits	$	500
Canadian exploration expense		140
Canadian development expense		17
Undepreciated capital costs		21
	$	678
Total tax pools and credits	$	1,688

2023 Guidance

Our current tax guidance is 5 - 6% of adjusted funds flow before tax for 2023, assuming WTI of $80.00/bbl and NYMEX of $3.50/Mcf.

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, commodity derivative contracts, 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 EBITDA¹”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At December 31, 2022, our senior debt to adjusted EBITDA ratio was 0.2x and our net debt to adjusted funds flow ratio was 0.2x. Although a capital management measure that 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.

22ENERPLUS 2022 FINANCIAL SUMMARY

Net debt at December 31, 2022 decreased to $221.5 million, compared to $640.4 million at December 31, 2021. Total debt was comprised of our senior notes and Bank Credit Facilities, totaling $259.5 million, less cash on hand of $38.0 million. At December 31, 2022, through our Bank Credit Facilities, we had total credit capacity of $1.3 billion, of which $56.3 million was drawn. We expect to finance our working capital requirements through cash, adjusted funds flow and our credit capacity. We have sufficient liquidity to meet our financial commitments for the near term.

Our reinvestment rate was 35% for 2022 compared to 42% in 2021.

During 2022, a total of $452.5 million, representing 57% of free cash flow¹, was returned to shareholders through share repurchases and dividends, compared to $153.7 million in 2021. In 2022, a total of 27,924,842 common shares were repurchased under the NCIB at an average price of $14.71 per share (December 31, 2021 – 12,897,721 shares, $9.55 per share). Subsequent to December 31, 2022 and up to and including February 22, 2023, we repurchased 1,420,927 common shares under the NCIB at an average price of $16.65 per share, for total consideration of $23.7 million.

For the year ended December 31, 2022, Enerplus increased its quarterly dividend three times resulting in a 67% increase to $0.055 per common share and paid a total of $41.6 million (December 31, 2021 – $30.5 million).

We plan to continue to return at least 60% of free cash flow¹ to our shareholders in 2023 through share repurchases and dividends, based on current market conditions. Remaining free cash flow not allocated to return of capital is expected to be directed to reinforcing the balance sheet. We intend to renew the NCIB in August 2023. Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share to be paid in March 2023. We expect to fund the dividend through the free cash flow generated by the business.

During the first quarter of 2022, Enerplus converted its senior unsecured, covenant-based, $400 million term loan maturing on March 9, 2024 into a revolving bank credit facility with no other amendments. During the fourth quarter of 2022, Enerplus converted this revolving bank credit facility to a $365 million SLL bank credit facility and extended the maturity to October 31, 2025. The $365 million SLL bank credit facility has the same targets as Enerplus’ $900 million SLL bank credit facility, which was renewed with $50 million maturing on October 31, 2025, and $850 million maturing on October 31, 2026. There were no other significant amendments or additions to the two agreements’ terms or covenants.

The SLL Bank Credit Facilities incorporate environmental, social and governance (“ESG”)-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus’ sustainability performance targets (“SPT”) are exceeded or missed. The SPTs are based on the following ESG goals of the Company:

● GHG Emissions: continuous progress toward Enerplus’ stated goal of a 35% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2021 as a baseline and measurement based on Enerplus’ annual internal targets;

● Water Management: achieve a 50% reduction in freshwater usage in corporate well completions by 2025 or earlier compared to 2019; and

● Health & Safety: achieve and maintain a 25% reduction in the Company’s Lost Time Injury Frequency, based on a trailing 3-year average, relative to a 2019 baseline.

At December 31, 2022, we were in compliance with all covenants under the Bank Credit Facilities and outstanding senior notes. If we exceed or anticipate exceeding our covenants, we may be required to repay, refinance or renegotiate the terms of the debt. See "Risk Factors – Debt covenants of the Company may be exceeded with no ability to negotiate covenant relief" in the Annual Information Form. Agreements relating to our Bank Credit Facilities and senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com.  

¹ This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

ENERPLUS 2022 FINANCIAL SUMMARY             23

The following table lists our financial covenants, as defined by our debt agreements, at December 31, 2022:

Covenant Description		December 31, 2022
Bank Credit Facilities:	Maximum Ratio
Senior debt to adjusted EBITDA	3.5x	0.2x
Total debt to adjusted EBITDA	4.0x	0.2x
Total debt to capitalization	55%	13%
Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA(1)	3.0x - 3.5x	0.2x
Senior debt to consolidated present value of total proved reserves(2)	60%	6%
	Minimum Ratio
Adjusted EBITDA to interest	4.0x	54.3x

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 twelve months ended December 31, 2022 was $1,332.6 million.

“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 $823.7 million adjustment related to our adoption of U.S. GAAP.

Footnotes

(1) 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.

(2) 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%.

Counterparty Credit

CRUDE OIL AND NATURAL GAS SALES COUNTERPARTIES

Our crude oil and natural gas receivables are with customers in the 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, 2022, we had $36.5 million in financial derivative assets offset by $10.4 million of financial derivative liabilities resulting in a net asset position of $26.1 million (December 31, 2021 – assets of $5.7 million, offset by liabilities of $150.3 million, resulting in a net liability position of $144.6 million).

Dividends

($ millions, except per share amounts)	2022		2021		2020
Dividends(1)	$	41.6	$	30.5	$	20.0
Per weighted average share (Basic)	$	0.181	$	0.121	$	0.090

(1) Excludes changes in non-cash financing working capital.

During 2022, we declared dividends of $0.181 per weighted average common share totaling $41.6 million (2021 – $0.121 per share and $30.5 million; 2020 – $0.090 per share and $20.0 million).

In 2022, we declared a quarterly dividend of $0.033 per common share for the first quarter, $0.043 per common share for the second quarter, $0.050 per common share for the third quarter, and $0.055 per common share for the fourth quarter. Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share to be paid in March 2023.

24ENERPLUS 2022 FINANCIAL SUMMARY

We expect to fund the dividend through the free cash flow generated by the business. The dividend is a part of our strategy to return capital to shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders’ Capital

	2022		2021		2020
Share capital ($ millions)	$	2,837.3	$	3,094.1	$	3,113.8
Common shares outstanding (thousands)		217,285		243,852		222,548
Weighted average shares outstanding – basic (thousands)		233,946		251,909		222,503
Weighted average shares outstanding – diluted (thousands)		242,673		259,851		222,503

For the twelve months ended December 31, 2022, a total of 2,411,783 units vested pursuant to our treasury settled LTI plans (2021 – 2,014,193; 2020 – 2,044,718). In total, 1,358,000 common shares were issued from treasury and $10.0 million was transferred from paid-in capital to share capital (2021 – 1,140,000 and $9.4 million; 2020 – 1,160,000 and $10.7 million). We elected to cash settle the remaining units related to the required tax withholdings (2022 - $13.4 million, 2021 – $3.6 million, ­2020 – $5.6 million).

In July 2022, Enerplus completed its previous NCIB by repurchasing 10% of its outstanding shares. On August 16, 2022, Enerplus renewed its NCIB to purchase up to 10% of the public float (within the meaning under Toronto Stock Exchange rules) during the following 12-month period. As a result, in 2022, 27,924,842 common shares were repurchased and cancelled under the NCIB at an average price of $14.71 per common share, for total consideration of $410.9 million. Of the amount paid, $266.7 million was charged to share capital and $144.2 million was added to accumulated deficit. At December 31, 2022, 7,883,479 common shares were available for repurchase under the current NCIB.

Subsequent to December 31, 2022 and up to and including February 22, 2023, we repurchased 1,420,927 common shares under the NCIB at an average price of $16.65 per share, for total consideration of $23.7 million.

As of February 22, 2023, we had 216,479,610 common shares outstanding. In addition, an aggregate of 9,699,445 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.

Commitments and Contingencies

We have the following minimum annual contractual commitments:

													Total
			Minimum Annual Commitment Each Year										Committed
($ millions)	Total		2023		2024		2025		2026		2027		after 2027
Senior notes(1)	$	203.2	$	80.6	$	80.6	$	21.0	$	21.0	$	—	$	—
Transportation commitments		487.6		71.3		72.6		73.4		74.0		61.9		134.4
Service workover rigs commitments		7.9		7.9		—		—		—		—		—
Operating lease obligations		24.0		14.3		6.5		1.1		1.0		1.0		0.1
Purchase commitments		2.1		2.1		—		—		—		—		—
Total commitments(2)(3)	$	724.8	$	176.2	$	159.7	$	95.5	$	96.0	$	62.9	$	134.5

(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) CDN$ commitments have been converted to US$ using the December 31, 2022 foreign exchange rate of 0.74.

In the Marcellus, we have firm transportation agreements in place for approximately 64,900 Mcf/day of gross natural gas volumes, which expire between 2023 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 gross natural gas volumes until mid-2027, reducing to 15,000 Mcf/day for an additional 9 years, with a total estimated transportation commitment of $62.7 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 as well as mid-2031.

We have firm commitments in place for the operation of service workover rigs for $7.9 million for 2023.

ENERPLUS 2022 FINANCIAL SUMMARY             25

SELECTED ANNUAL U.S. AND CANADIAN FINANCIAL RESULTS

	Year ended December 31, 2022							Year ended December 31, 2021
($ millions, except per unit amounts)		U.S.		Canada		Total		U.S.		Canada		Total
Average Daily Production Volumes
Crude oil (bbls/day)			47,511		4,506		52,017		42,981		5,533		48,514
Natural gas liquids (bbls/day)			9,439		242		9,681		7,500		323		7,823
Natural gas (Mcf/day)			225,667		6,103		231,770		207,242		8,062		215,304
Total average daily production (BOE/day)			94,561		5,765		100,326		85,021		7,200		92,221
Pricing(1)
Crude oil (per bbl)		$	94.94	$	79.83	$	93.63	$	67.30	$	55.00	$	65.89
Natural gas liquids (per bbl)			30.11		53.90		30.70		29.20		36.80		29.51
Natural gas (per Mcf)			5.53		4.90		5.51		2.90		3.78		2.94
Property, Plant and Equipment
Capital and office expenditures		$	426.5	$	6.8	$	433.3	$	289.5	$	14.4	$	303.9
Property and land acquisitions			21.3		1.2		22.5		832.8		2.3		835.1
Property and land divestments			(18.4)		(213.0)		(231.4)		(108.0)		(4.7)		(112.7)
Netback Before Impact of Commodity Derivative Contracts(2)
Crude oil and natural gas sales		$	2,205.9	$	147.5	$	2,353.4	$	1,355.3	$	127.3	$	1,482.6
Operating expenses			(324.9)		(40.8)		(365.7)		(250.7)		(41.7)		(292.4)
Transportation costs			(150.0)		(4.7)		(154.7)		(122.2)		(6.1)		(128.3)
Production taxes			(164.4)		(2.6)		(167.0)		(99.9)		(2.1)		(102.0)
Netback before impact of commodity derivative contracts		$	1,566.6	$	99.4	$	1,666.0	$	882.5	$	77.4	$	959.9
Other Expenses
Commodity derivative instruments loss/(gain)			—		197.7		197.7		—		274.4		274.4
General and administrative expense(3)			42.4		27.6		70.0		35.4		21.4		56.8
Current income tax expense/(recovery)			28.1		—		28.1		2.7		—		2.7

(1) Before transportation costs and the effects of commodity derivative instruments.

(2) This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

(3) Includes share-based compensation.

THREE YEAR SUMMARY OF KEY MEASURES

($ millions, except per share amounts)	2022		2021		2020
Crude oil and natural gas sales	$	2,353.4	$	1,482.6	$	553.7
Net income/(loss)		914.3		234.4		(693.4)
Per share (Basic)		3.91		0.93		(3.12)
Per share (Diluted)		3.77		0.90		(3.12)
Adjusted net income(1)		707.1		315.7		14.5
Cash flow from operating activities		1,173.4		604.8		335.9
Adjusted funds flow		1,230.3		712.4		265.5
Dividends(2)		41.6		30.5		20.0
Per share (Basic)(2)		0.181		0.121		0.090
Total assets		1,938.0		1,990.1		1,152.4
Total debt		259.5		701.8		385.4
Net debt		221.5		640.4		295.5
Total non-current financial liabilities		358.2		759.3		424.6

(1) This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this MD&A.

(2) Calculated based on dividends paid and/or payable.

26ENERPLUS 2022 FINANCIAL SUMMARY

2022 versus 2021

Crude oil and natural gas sales were $2,353.4 million in 2022 compared to $1,482.6 million in 2021. We reported net income of $914.3 million in 2022 compared to a net income of $234.4 million in 2021. The increases were due to higher realized commodity prices and increased production from the acquisitions in North Dakota completed during the first half of 2021, increased completions activity in North Dakota and the Marcellus, and the gain on the sale of Canadian assets.

Cash flow from operating activities and adjusted funds flow increased to $1,173.4 million and $1,230.3 million, respectively, in 2022 from $604.8 million and $712.4 million in 2021. The increase was primarily the result of a $870.8 million increase in crude oil and natural gas sales due to higher realized commodity prices and higher production.

2021 versus 2020

Crude oil and natural gas sales were $1,482.6 million in 2021 compared to $553.7 million in 2020. We reported net income of $234.4 million in 2021 compared to a net loss of $693.4 million in 2020. The increases were due to higher realized commodity prices and increased production from the Bruin and Dunn County acquisitions as well as lower non-cash impairments in 2021 compared to 2020.

Cash flow from operating activities and adjusted funds flow increased to $604.8 million and $712.4 million, respectively, in 2021 from $335.9 million and $265.5 million in 2020. The increase was primarily the result of a $928.8 million increase in crude oil and natural gas sales due to higher realized commodity prices and higher production.

QUARTERLY FINANCIAL INFORMATION

	Crude Oil and		Net		Net Income/(Loss) Per Share
($ millions, except per share amounts)	Natural Gas Sales		Income/(Loss)		Basic		Diluted
2022
Fourth Quarter	$	548.7	$	330.7	$	1.49	$	1.43
Third Quarter		663.5		305.9		1.32		1.28
Second Quarter		628.0		244.4		1.01		0.99
First Quarter		513.2		33.2		0.14		0.13
Total 2022	$	2,353.4	$	914.3	$	3.91	$	3.77
2021
Fourth Quarter	$	499.7	$	176.9	$	0.71	$	0.68
Third Quarter		421.1		98.1		0.38		0.38
Second Quarter		333.4		(50.9)		(0.20)		(0.20)
First Quarter		228.4		10.3		0.04		0.04
Total 2021	$	1,482.6	$	234.4	$	0.93	$	0.90

During 2022, crude oil and natural gas sales increased due to higher production and improved realized pricing. Net income decreased during the first quarter of 2022 due to a $206.8 million loss recorded on commodity derivative instruments as a result of higher commodity prices. Net income increased during the second quarter of 2022 due to a smaller loss recorded on commodity derivative instruments of $47.6 million. During the second half of 2022, net income increased due to a commodity derivative instruments gain of $57.0 million in the third quarter of 2022, and $151.9 million gain on the sale of the Canadian assets in the fourth quarter of 2022.

During 2021, crude oil and natural gas sales increased due to improvements in commodity prices in the first quarter. During the second quarter, crude oil and natural gas sales increased due to higher production from the Bruin and Dunn County acquisitions. The net loss in the same period was primarily due to commodity derivative instrument losses as a result of the higher commodity prices as crude oil demand continued to improve. During the second half of 2021, commodity prices continued to increase, and additional wells came on production which resulted in higher net income.

ENERPLUS 2022 FINANCIAL SUMMARY             27

ENVIRONMENTAL, 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-related risks and initiatives. Specific accountability for our five material focus areas have been mapped to the relevant Board committees, including the Compensation and Human Resources Committee, and the Reserves, Safety and Social Responsibility Committee (the “RS&SR Committee”).The five material focus areas are: 

● Emissions Management

● Water Management

● Culture

● Community Engagement

● Health and Safety

As part of our continued integration of ESG issues into our business strategy and operations, in 2022 we updated targets for reducing Scope 1 and Scope 2 GHG emissions and methane emissions intensities. Using 2021 as a baseline, we targeted a 30% reduction of our methane emissions intensity per BOE by the end of 2025, and a 50% reduction by 2030. We have revised our long-term GHG emissions reduction target of reducing our Scope 1 and Scope 2 emissions intensity by 35% by 2030 relative to our 2021 baseline. During 2022, we reduced our methane emissions intensity by 9% and reduced 2022 Scope 1 and Scope 2 GHG emissions intensity by approximately 16%, based on preliminary estimates, from our 2021 baseline. Final results will be available in our annual ESG Report and Data Tables, expected to be published later in 2023.

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 2022, we reported an LTIF of 0.06 injuries per 200,000 worker hours, down from 0.08 in 2019. We will continue to update the market as we progress closer to the end of our 2023 target.

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 overseeing compliance with these policies. The RS&SR Committee of our Board of Directors is responsible for overseeing our H&S performance and safety and social responsibility risks. The Board of Directors are responsible for overseeing our ESG performance, risks and strategy. We believe that this governance structure promotes adequate systems in place to support ongoing compliance, and to plan the Company’s activities in a safe, socially responsible and sustainable manner.  

The RS&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 impose more stringent compliance requirements. 

Annually, we publish an ESG Report in accordance with the Sustainability Accounting Standards Boards (“SASB”) Oil and Gas – Exploration and Production Standard materiality map, 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). Additionally, in conjunction with our ESG Report, we publish a Reporting Table based on recommendations of the Task Force on Climate Related Financial Disclosure (“TCFD”). Our ESG report summarizes our approach to and performance related to environmental, safety, social responsibility and governance performance, and can be found on our website at www.enerplus.com. In 2022, Enerplus underwent an external audit of selected ESG metrics representing its public targets. Enerplus received Limited Assurance on its absolute Scope 1 and 2 emissions, Scope 1 and 2 emissions intensities, produced water inclusion in completions activities, and LTIF. In 2022, we published metrics in line with the American Exploration and Production Council ESG Framework, which can also be found on our website.  

28ENERPLUS 2022 FINANCIAL SUMMARY

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 expenditures. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

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 that may arise upon disposition of crude oil and natural gas properties and purchase equations associated with business combinations. 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 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.

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, the estimated timing of the costs to be incurred in future periods and the appropriate credit adjusted risk free rate. 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 2022 FINANCIAL SUMMARY             29

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 crude oil and natural 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.

The fair value of commodity contracts and the equity swaps is estimated based on commodity and option pricing models that incorporate various factors including forecasted commodity prices, volatility and the credit risk of the entries party to the contract. Changes and variability in commodity prices over the term of 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. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates, discount rates used to present value the instrument and counterparty credit risk.

RISK FACTORS AND RISK MANAGEMENT  

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

● the ability to export from North America

● geopolitical uncertainty, including the ongoing conflict in Ukraine

● sustained pandemics or epidemics, including the continuing effect of the COVID-19 pandemic, which may disrupt economies, whether local or global, and may impact supply, demand and prices for crude oil, natural gas liquids and natural gas

● global gross domestic product growth

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

● the production and storage levels of global crude oil, natural gas and natural gas liquids

● supply chain challenges and disruptions

● weather conditions

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

● the effect of world-wide energy conservation and greenhouse gas reduction measures

● the price and availability of alternative fuels

● 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 capital expenditures available 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 when market conditions are less satisfactory for Enerplus. 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 commodity derivative mechanisms to help limit the adverse effects of crude oil, natural gas liquids, and natural gas price volatility. However, we do not have commodity contracts in place for all 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. As of February 22, 2023, we have 15,000 bbls/day hedged for first half of 2023 and 5,000 bbls/day hedged for the second half of 2023. We have also hedged 120,000 Mcf/day for the period from January 1, 2023 to March 31, 2023 and 50,000 Mcf/day for the period from April 1, 2023 to October 31, 2023. Refer to the “Price Risk Management” section for further details on our price risk management program.

30ENERPLUS 2022 FINANCIAL SUMMARY

Risks Relating to the Impact of the Ukraine and Russia conflict

The existing conflict between Ukraine and Russia and the international response has, and may continue to have, potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Certain countries including Canada, the United States, Australia and certain European countries have imposed strict financial and trade sanctions against Russia, which may have continued far-reaching effects on the global economy, energy and commodity prices and food security and crop nutrient supply and prices. The short-, medium- and long-term implications of the conflict in Ukraine are difficult to predict with any degree of certainty at this time. Depending on the extent, duration, and severity of the conflict, it may have the effect of heightening many of the other risks described in our Annual MD&A and our Annual Information Form, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of capital; and supply chains and cost effective and timely transportation.

Risk of Increasing Attention to ESG and Sustainability Matters

Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability 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 the business, financial condition, and/or stock price could be materially and adversely affected. Increasing attention to climate change and sustainability, increasing societal expectations on companies to address climate change-related targets, and potential consumer use of substitutes to fossil-fuel energy commodities may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts to our stock price and access to capital markets. Increasing attention to climate change-related and sustainability targets and expected actions, for example, may result in demand shifts for hydrocarbon products and additional governmental investigations and private litigation against Enerplus.

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 the Corporation’s shares from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of the Corporation's operations by certain investors. Additionally, to the extent ESG matters negatively impact the Corporation’s reputation, it may not be able to compete as effectively to recruit or retain employees, which may adversely affect its operations.

The Corporation also makes certain disclosures regarding sustainability, publishing an ESG report that provides updates on its performance related to certain ESG topics and sets certain ESG goals. Many of its disclosures are necessarily based on estimates and assumptions that are inherently difficult to assess. Moreover, Enerplus may not be able to adequately identify ESG-related risks and opportunities and, further, may not be able to meet ESG targets in the manner, or on such a timeline as initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. While the Corporation may elect to seek out various additional voluntary ESG targets now or in the future, such targets are aspirational. Notwithstanding this, Enerplus may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but it cannot guarantee it will be able to implement such goals because of potential costs or technical or operational obstacles.

Additionally, public statements with respect to emissions reduction goals, environmental targets, or, more broadly, ESG-related goals, are becoming increasingly subject to heightened scrutiny from public and governmental authorities with respect to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. The Canadian securities regulators (the “CSA”) have been monitoring issuers’ disclosures relating to various ESG-related matters and have published a public guidance stating their concerns with certain practices involving unsupported claims that may constitute greenwashing. Certain non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, to include emission reduction goals or standards used, were misleading, false, or otherwise deceptive. As a result, the Corporation may face increased litigation risks which could, in turn, lead to further negative sentiment and diversion of investments. Enerplus could also face increasing costs to comply with increased regulatory focus and scrutiny.

ENERPLUS 2022 FINANCIAL SUMMARY             31

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, the gathering, transportation 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 penalties, 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 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 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, federal, tribal and municipal levels, the actual cost impact and its materiality to our business remains uncertain.

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, facilities and infrastructure, including limited water availability, severe weather causing flooding, prolonged drought and/or wildfires. 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 economy, including the risk of regulatory and policy change and reputational concerns. The global push to meet net zero emission targets by 2050 increases the risk of potentially burdensome regulatory and/or policy changes from governments, some of which could have a direct, negative impact on Enerplus should they impede access or negatively impact our relationship with our stakeholders, debt holders, insurers, and the investment community or various service providers. In addition, as a result of these regulations and policies, Enerplus could also have stranded assets, for example, be unable to obtain value for, or from, its reserves.

More specific concerns of the fossil fuels, for the industry relate to GHG emissions, including methane, as well as water and land use. More stringent legislation or regulations in the United States and Canada, relative to other jurisdictions, including requirements to significantly reduce GHG emissions, water consumption or setback requirements for facilities and wells, could result in increased costs and competitive disadvantages. In addition, a potential increase in capital expenditures, operating expenses, abandonment and reclamation obligations 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 our inability to continue development of assets.

32ENERPLUS 2022 FINANCIAL SUMMARY

There is also a risk that financial institutions will adopt, or be pressured, or 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. As a result of new initiatives, we could be required to adopt new technologies, and make a significant investment in capital resources. These initiatives could also result in additional costs if climate-related targets are not achieved, therefore negatively impacting our results and economics.The CSA and the SEC have separately released proposed rules that would establish a framework for the reporting of climate risks, targets, and metrics. Although the final form and substance of this rule and its requirements are not yet known, and the ultimate impact on the Corporation is uncertain, the proposed rule, if finalized, may result in increased compliance costs and increased costs of and restrictions on access to capital.

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 our Board of Directors and applicable Board committees. Our strategy is to be a responsible operator from the perspective of our shareholders, employees, contractors, regulators, lenders, communities and the general public. Despite these efforts, activities undertaken directly by Enerplus or its employees in operating its business, or by others in industry, could adversely affect Enerplus’ reputation. If our reputation, 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; negative relationships with Indian Reservations and Indigenous groups; or a loss of public support in general.

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 since the COVID-19 pandemic and the Russia and Ukraine conflict, with cybercriminals taking advantage of remote working environments to increase malicious activities creating more threats for cyberattacks. These include phishing emails, malware-embedded mobile apps that purport to track infection rates and targeting of vulnerabilities in remote access platforms. Although we have security measures and controls in place that are designed to mitigate these risks, the growing use of the digital space could increase technological risks (example, by monitoring/intercepting phones and communications, or surveilling or locating persons of interest) further increasing the risk of a breach of our security, which could 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. In addition, third-party operators on whom we depend on, and the operations of our customers and business partners are also subject to such risks. 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.

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 steel, proppant, pumper services, and operating costs such as electricity, chemicals, supplies, processing charges, 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, other supply chain challenges or disruptions and adverse effects of inflation and rising interest rates, may result in higher than expected supply costs. Additionally, we have certain service contracts tied to inflationary measure benchmarks (such as the Consumer Price Index and WTI crude oil price), which have increased and could further increase our operating costs should the benchmarks rise significantly.

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. Service providers, including those we rely on, are also in a highly competitive environment that is impacted by worker availability, commodity prices and global supply inventories. Where worker availability is impacted by shortages, due to location or pandemic related issues, for example, 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/supplies, and thereby the costs to producers. 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.

ENERPLUS 2022 FINANCIAL SUMMARY             33

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services through 2023, access to field services and supplies in other areas of our business will continue to be subject to market availability.

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.

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.

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.

34ENERPLUS 2022 FINANCIAL SUMMARY

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, 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 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 environmental regulation, government regulation, third-party operational practices, or low commodity prices, 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.

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 Canadian 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 Canadian NI 51-101 Standards and have been adjusted for the effects of SEC constant prices. Independent reserves evaluations have been conducted on 100% of the total proved plus probable net present value (discounted at 10% and using Canadian NI 51-101 Standards) of our reserves at December 31, 2022. McDaniel & Associates Consultants Ltd. (“McDaniel”) 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.

ENERPLUS 2022 FINANCIAL SUMMARY             35

The evaluation of best estimate development pending contingent resources associated with our North Dakota assets was conducted by McDaniel. NSAI evaluated our Marcellus shale gas best estimate development pending contingent resources. The RS&SR 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.

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.

No impairment was recorded in 2022. We recorded an impairment of $3.4 million related to our Canadian assets in 2021. In 2020, we recorded an impairment of $751.7 million (Canadian cost centre: $100.9 million, U.S. cost centre $650.8 million) on our crude oil and natural gas assets. We continue to record a valuation allowance against our capital related deferred tax assets, however, no valuation allowance was recorded in 2022 or 2021 against our income related deferred tax assets. In 2020, we reversed our valuation allowance of $11.5 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 in 2020. There is a risk of impairment on our oil and gas properties, and deferred tax asset 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 6 and 14 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) adverse weather conditions, such as freezing temperatures, storms, 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.

36ENERPLUS 2022 FINANCIAL SUMMARY

Risk of Exceeding Debt Covenants

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 Facilities 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 Facilities, or significant reductions to proved reserves may result in us breaching our debt covenants under the Bank Credit Facilities and senior notes. 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 Bank Credit Facilities or senior notes. Failure to comply with debt covenants, or negotiate relief, may result in our indebtedness under the Bank Credit Facilities or senior notes becoming immediately due and payable, which may have a material adverse effect on our operations and financial condition.

Risk of Insufficient Liquidity

Although we believe that our existing Bank Credit Facilities and senior notes 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 Bank Credit Facilities and senior notes may not be sufficient for future operations, or we may not be able to renew our Bank Credit Facilities or obtain additional financing on attractive economic terms, if at all. The Bank Credit Facilities are generally extendable each year with a bullet payment required at the end of the term if the facility is not renewed. The $365 million Bank Credit Facility currently matures on October 31, 2025; $50 million and $850 million of the $900 million Bank Credit Facility matures on October 31, 2025 and October 31, 2026, respectively. 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 Facilities or to renew its commitment in respect of such Bank Credit Facilities, 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 Bank Credit Facilities and senior notes has priority over dividend payments to our shareholders.

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.

Foreign Currency Exposure

Beginning with the year ended December 31, 2021, we elected to change our reporting currency from Canadian dollars to U.S. dollars since the majority of our crude oil and natural gas properties are located in the U.S. Transactions denominated in foreign currencies are translated to the functional currency of the entity (U.S. dollars for all of our entities) using the exchange rate prevailing at the date of the transaction and, in the case of Canadian entities, then translated to U.S. dollars for reporting purposes. As a result, transactions in Canadian entities are affected by the exchange rate between the U.S. and Canadian dollar, including U.S. dollar denominated debt held in our Canadian parent, Canadian denominated receipts and payments and Canadian dollar dividend payments.

Enerplus is exposed to foreign exchange risk as it relates to Canadian and U.S. dollar. Subsequent to December 31, 2022, on January 1, 2023, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a change in functional currency to U.S. dollars, consistent with the functional currency of the U.S. subsidiary. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At December 31, 2022, we did not have any foreign exchange derivatives outstanding.

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.

Enerplus’ senior notes bear interest at fixed rates while the Bank Credit Facilities bear interest at floating rates. At December 31, 2022, approximately 78% of Enerplus’ debt was based on fixed interest rates and 22% on floating interest rates (December 31, 2021 – 43% and 57% fixed), with weighted average interest rates of 4.2% and 5.7%, respectively (December 31, 2021 – 4.2%, 1.9%). At December 31, 2022 and 2021, Enerplus did not have any interest rate derivatives outstanding.

ENERPLUS 2022 FINANCIAL SUMMARY             37

ADJUSTED FUNDS FLOW SENSITIVITY

The sensitivities below reflect all of Enerplus’ commodity contracts listed in Note 16 to the Financial Statements and are based on 2023 guidance production and price levels of: WTI - $80.00/bbl, NYMEX - $3.50/Mcf and a CDN/US exchange rate of 0.75. To the extent crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.

	Estimated Effect on 2023
Sensitivity Table	Adjusted Funds Flow per Share(1)
Increase of $5.00 per barrel in the price of WTI crude oil	$	0.29
Decrease of $5.00 per barrel in the price of WTI crude oil	$	(0.28)
Increase of $0.50 per Mcf in the price of NYMEX natural gas	$	0.10
Decrease of $0.50 per Mcf in the price of NYMEX natural gas	$	(0.10)
Change of 1,000 BOE/day in production	$	0.06

(1) Calculated using 216.5 million shares outstanding at February 22, 2023.

2023 GUIDANCE⁽¹⁾

Summary of 2023 Annual Expectations	Target
Capital spending ($ millions)	$500 - $550
Average annual production (BOE/day)	93,000 - 98,000
Average annual crude oil and natural gas liquids production (bbls/day)	57,000 - 61,000
Average production tax rate (% of gross sales, before transportation)	7%
Operating expenses (per BOE)	$10.75 - $11.75
Transportation costs (per BOE)	$4.35
Cash G&A expenses (per BOE)	$1.35
Current tax expense (% of adjusted funds flow before tax)	5% - 6%

Differential/Basis Outlook(2)	Target
Average U.S. Bakken crude oil differential (compared to WTI crude oil)	$0.75/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)	($0.75)/Mcf

(1) This constitutes forward-looking information. Refer to “Forward-Looking Information and Statements” section in this MD&A.

(2) Excludes transportation costs.

38ENERPLUS 2022 FINANCIAL SUMMARY

NON-GAAP AND OTHER FINANCIAL MEASURES

Non-GAAP Financial Measures

This MD&A includes references to certain non-GAAP financial measures and non-GAAP ratios used by the Company to evaluate its financial performance, financial position or cash flow. Non-GAAP financial measures are financial measures disclosed by a company that (a) depict historical or expected future financial performance, financial position or cash flow of a company, (b) with respect to their composition, exclude amounts that are included in, or include amounts that are excluded from, the composition of the most directly comparable financial measure disclosed in the primary financial statements of the company, (c) are not disclosed in the financial statements of the company and (d) are not a ratio, fraction, percentage or similar representation. Non-GAAP ratios are financial measures disclosed by a company that are in the form of a ratio, fraction, percentage or similar representation that has a non-GAAP financial measure as one or more of its components, and that are not disclosed in the financial statements of the company.

These non-GAAP financial measures and non-GAAP ratios do not have standardized meanings or definitions as prescribed by U.S. GAAP and may not be comparable with the calculation of similar financial measures by other entities. For each measure, we have indicated the composition of the measure, identified the GAAP equivalency to the extent one exists, provided comparative detail where appropriate, indicated the reconciliation of the measure to the mostly directly comparable GAAP financial measure and provided details on the usefulness of the measure for the reader. These non-GAAP financial measures and non-GAAP ratios should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP.

“Adjusted net income/(loss)” is used by Enerplus and is useful to investors and securities analysts in evaluating the financial performance of the company by adjusting for certain unrealized items and other items that the company considers appropriate to adjust given their irregular nature. The most directly comparable GAAP measure is net income/(loss).

	Year ended December 31,
($ millions)		2022		2021		2020
Net income/(loss)		$	914.3	$	234.4	$	(693.4)
Unrealized derivative instrument (gain)/loss			(150.5)		109.5		18.1
Gain on divestment of assets			(151.9)		—		—
Unrealized foreign exchange (gain)/loss			11.2		(8.1)		1.4
Other expense related to investing activities			13.1		—		—
Asset impairment			—		3.4		751.7
Tax effect on above items			64.0		(24.9)		(201.0)
Income tax rate adjustment on deferred taxes			8.8		6.0		—
Other income related to investing activities			(1.9)		(4.6)		—
Goodwill impairment			—		—		149.2
Valuation allowance on deferred taxes			—		—		(11.5)
Adjusted net income/(loss)		$	707.1	$	315.7	$	14.5

“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. The most directly comparable GAAP measure is cash flow from operating activities.

	Year ended December 31,
($ millions)		2022		2021		2020
Cash flow from/(used in) operating activities		$	1,173.4	$	604.8	$	335.9
Asset retirement obligation settlements			17.4		13.0		13.3
Changes in non-cash operating working capital			39.5		94.6		(83.7)
Adjusted funds flow		$	1,230.3	$	712.4	$	265.5
Capital spending			(432.0)		(302.3)		(217.2)
Free cash flow		$	798.3	$	410.1	$	48.3

ENERPLUS 2022 FINANCIAL SUMMARY             39

“Netback before impact of commodity derivative contracts” and “Netback after impact of commodity derivative contracts” is used by Enerplus and is useful to investors and securities analysts, in evaluating operating performance of our crude oil and natural gas assets, both before and after consideration of our realized gain/(loss) on commodity derivative instruments. A direct GAAP equivalent does not exist for these measures, although a reconciliation is provided below:

	Year ended December 31,
($ millions)		2022		2021		2020
Crude oil and natural gas sales		$	2,353.4	$	1,482.6	$	553.7
Less:
Operating expenses			(365.7)		(292.4)		(197.1)
Transportation expenses			(154.7)		(128.3)		(98.7)
Production taxes			(167.0)		(102.0)		(37.4)
Netback before impact of commodity derivative contracts		$	1,666.0	$	959.9	$	220.5
Net realized gain/(loss) on derivative instruments			(347.2)		(163.0)		92.9
Netback after impact of commodity derivative contracts		$	1,318.8	$	796.9	$	313.4

Other Financial Measures

CAPITAL MANAGEMENT MEASURES

Capital management measures are financial measures disclosed by a company that (a) are intended to enable an individual to evaluate a company’s objectives, policies and processes for managing the company's capital, (b) are not a component of a line item disclosed in the primary financial statements of the company, (c) are disclosed in the notes to the financial statements of the company, and (d) are not disclosed in the primary financial statements of the company. The following section provides an explanation of the composition of those capital management measures if not previously provided:

“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts, in analyzing operating and financial performance, leverage and liquidity. The most directly comparable GAAP measure is cash flow from operating activities. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.

“Net Debt” is calculated as current and long-term debt associated with senior notes plus any outstanding Bank Credit Facilities balances, less cash and cash equivalents. “Net debt” is useful to investors and securities analysts in analyzing financial liquidity and Enerplus considers net debt to be a key measure of capital management.

“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 net debt divided by a trailing twelve months of adjusted funds flow.There is no directly comparable GAAP equivalent for this measure, and it is not equivalent to any of our debt covenants.

SUPPLEMENTARY FINANCIAL MEASURES

Supplementary financial measures are financial measures disclosed by a company that (a) are, or are intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of a company, (b) are not disclosed in the financial statements of the company, (c) are not non-GAAP financial measures, and (d) are not non-GAAP ratios. The following section provides an explanation of the composition of those supplementary financial measures if not previously provided:

“Capital spending” Capital and office expenditures, excluding other capital assets/office capital and property and land acquisitions and divestments.

“Cash general and administrative expenses” or “Cash G&A expenses” General and administrative expenses that are settled through cash payout, as opposed to expenses that relate to accretion or other non-cash allocations that are recorded as part of general and administrative expenses.

“Cash share-based compensation” or “Cash SBC expenses” Share-based compensation that is settled by way of cash payout, as opposed to equity settled.

“Reinvestment rate” Comparing the amount of our capital spending to adjusted funds flow (as a percentage).

40ENERPLUS 2022 FINANCIAL SUMMARY

INTERNAL CONTROLS AND PROCEDURES

Internal Controls over Financial Reporting

We maintain internal controls over financial reporting that are 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, 2022, management has concluded that our internal controls over financial reporting are effective.  

The effectiveness of internal controls over financial reporting as of December 31, 2022 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.

Due to inherent limitations, internal controls over financial reporting are 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 2022 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, 2022, 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.

ENERPLUS 2022 FINANCIAL SUMMARY             41

PRESENTATION OF RESERVES INFORMATION

All of Enerplus’ reserves have been evaluated in accordance with Canadian reserve evaluation standards under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“Canadian NI 51-101 Standards”). Independent reserves evaluations have been conducted on properties comprising 100% of the net present value (discounted at 10%, before tax, using January 1, 2023 forecast prices and costs) of Enerplus’ total proved plus probable reserves. McDaniel, an independent petroleum consulting firm based in Calgary, Alberta, has evaluated all of Enerplus’ proved plus probable reserves associated with the Enerplus’ properties located in North Dakota and Colorado. NSAI, independent petroleum consultants based in Dallas, Texas, has evaluated all of Enerplus’ reserves associated with Enerplus’ properties in Pennsylvania in accordance with Canadian NI 51-101 Standards. For consistency in the Enerplus’ reserves reporting, NSAI also used the average commodity price forecasts and inflation rates of McDaniel, GLJ Ltd. and Sproule Associates Limited, independent petroleum consultants, as of January 1, 2023 to prepare its report.

Enerplus has also presented certain reserves information effective December 31, 2022 in accordance with the provisions of the Financial Accounting Standards Board’s ASC Topic 932 Extractive Activities – Oil and Gas, which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the SEC, but does not necessarily include all of the disclosure required by the SEC disclosure standards set forth in Subpart 1200 of Regulation S-K (the "U.S. Standards"). Concurrent to the evaluation of Enerplus’ Canadian NI 51-101 Standards reserves, McDaniel and NSAI prepared and reviewed estimates of Enerplus’ reserves under the U.S. Standards. The practice of preparing production and reserves data under Canadian NI 51-101 Standards differs from the U.S. Standards. The primary differences between the two reporting requirements include:

● the Canadian NI 51-101 Standards require disclosure of proved and probable reserves, while the U.S. Standards require disclosure of only proved reserves;

● the Canadian NI 51-101 Standards require the use of forecast prices in the estimation of reserves, while the U.S. Standards require the use of 12-month average trailing historical prices, which are held constant;

● the Canadian NI 51-101 Standards require disclosure of reserves on a gross (before royalties) and net (after royalties) basis, while the U.S. Standards require disclosure on a net (after royalties) basis;

● the Canadian NI 51-101 Standards require disclosure of production on a gross (before royalties) basis, while the U.S. Standards require disclosure on a net (after royalties) basis;

● the Canadian NI 51-101 Standards require that reserves and other data be reported on a more granular product type basis than required by the U.S. Standards; and

● the Canadian NI 51-101 Standards require that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves.

F&D costs presented in this MD&A are calculated (i) in the case of F&D costs for proved developed producing reserves, by dividing the sum of the exploration and development costs incurred in the year, by the additions to proved developed producing reserves in the year, (ii) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves in the year, and (iii) in the case of F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs related to its reserves additions for that year. F&D costs are presented in U.S. dollars per net of gross BOE as specified.

Complete disclosure of our oil and gas reserves and other oil and gas information presented in accordance with Canadian NI 51-101 Standards, as well as supplemental information presented in accordance with U.S. Standards,is contained within our AIF, which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at www.sec.gov.

42ENERPLUS 2022 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: expected 2023 average production volumes, timing thereof and the anticipated production mix; expected increase in gas processing and higher well service activity; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; adjusted funds flow sensitivity and the estimated effect on adjusted funds flow per share in 2023; oil and natural gas prices and differentials; expectations regarding market environment and our commodity risk management program in 2023 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, transportation and tax expenses; expected free cash flow generation and use thereof, including to fund share repurchases and dividends; the anticipated percentage of free cash flow planned to be returned to shareholders; the anticipated renewal of our NCIB and the timing thereof; capital spending levels in 2023 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 and timing of our future abandonment and reclamation costs and asset retirement obligations and the source of funds necessary in order to pay such obligations; our ESG initiatives, including Scope 1 and Scope 2 GHG emissions and methane emissions intensity and health and safety targets; future environmental expenses; our future royalty and production and cash taxes; deferred income taxes, our tax pools and the time at which we may pay cash taxes; future debt and working capital levels, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with or renegotiate debt covenants under our Bank Credit Facilities and outstanding senior notes; our future acquisitions and dispositions; and the amount of future cash dividends that we may pay to our shareholders and the source of funds necessary in order to pay such dividends.

The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation:the ability to fund our return of capital plans, including both dividends at the current level and the share repurchase program, from free cash flow as expected; that our common share trading price will be at levels, and that there will be no other alternatives, that, in each case, make share repurchases an appropriate and best strategic use of our free cash flow; 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 and anticipated commodity prices, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions;the impact of inflation, weather conditions, storage fundamentals and expectations regarding the duration and overall impact of the continued conflict in Ukraine and the COVID-19 pandemic 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 Facilities to fund our working capital deficiency;our ability to comply with our debt covenants; our ability to meet the targets associated with Bank Credit Facilities; the availability of third party services;factors used to assess the realizability of our deferred income tax assets; the extent of our liabilities; and the availability of technology and process to achieve environmental targets. In addition, our 2023 guidance contained in this MD&A is based on the following: a WTI price of $80.00/bbl, a NYMEX price of $3.50/Mcf, a Bakken crude oil price differential of $0.75/bbl above WTI, a Marcellus natural gas price differential of $0.75/Mcf below NYMEX and a CDN/US exchange rate of 0.75. 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 term material, in reference to the ESG material focus areas, is not used for, does not have, and is not intended to have, the same meaning as such term is assigned under applicable securities laws, including, but not limited to, with respect to financial materiality, materiality to investors or creditors, enterprise value, or other indications of financial impact, and is used solely to reflect the Company’s identification of those ESG issues that the Company has determined within its judgement present significant ESG risks or opportunities to its operations.

ENERPLUS 2022 FINANCIAL SUMMARY             43

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 instability, or further deterioration, in global economic and market conditions, including from COVID-19 or similar events, inflation and/or Ukraine/Russia conflict and heightened geopolitical risk; decreases in commodity prices or volatility in commodity prices; changes in realized prices of Enerplus’ products from those currently anticipated; changes in the demand for or supply of our products,including global energy demand and including as a result of ongoing disruptions to global supply chains; volatility in our common share trading price and free cash flow that could impact our planned share repurchases and dividend levels; 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 andincreased capital and operating costs resulting therefrom; inability to comply with applicable environmental government regulations or regulatory approvals and resulting compliance and enforcement actions; 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 Facilities 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; changes in law or government programs or policies in Canada or the Unites States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in this MD&A, our AIF and Form 40-F as at December 31, 2022).

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.Any forward-looking information contained herein is expressly qualified by this cautionary statement.

44ENERPLUS 2022 FINANCIAL SUMMARY

EX-99.4

EXHIBIT 99.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Enerplus Corporation

We consent to the use of:

● our report dated February 23, 2023 on the consolidated financial statements of Enerplus Corporation (the Company) which comprise the consolidated balance sheets as of December 31, 2022 and 2021, 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, 2022, and the related notes, and

● our report dated February 23, 2023 on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2022

each of which is included in the Annual Report on Form 40-F of the Company for the fiscal year ended December 31, 2022.

We also consent to the incorporation by reference of such reports in the Registration Statements on Form S-8 (No. 333-200583), and Form F-10 (No. 333-257151) of the Company.

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 23, 2023

EX-99.5

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 23, 2023 for the year ended December 31, 2022, which document makes reference to our firm and our reports dated February 3, 2023, evaluating the Registrant's oil, natural gas and natural gas liquids interests effective December 31, 2022 and the Registrant’s registration statements on Form F-10 (File No. 333-257151) and Form F-8 (File No. 333-200583) filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

Calgary, Alberta, Canada February 22, 2023	MCDANIEL & ASSOCIATES CONSULTANTS LTD.
	/s/ Brian R. Hamm
	Brian R. Hamm, P.Eng.
	President & CEO

EX-99.6

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 23, 2023, for the year ended December 31, 2022, which document makes reference to our firm and our report dated February 17, 2023, evaluating the Registrant's shale gas and contingent resources interests effective December 31, 2022 and the Registrant’s registration statements on Form F-10 (File No. 333-257151) and Form F-8 (File No. 333-200583) filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

Dallas, Texas February 22, 2023	NETHERLAND, SEWELL & ASSOCIATES, INC.
	/s/ Richard B. Talley, Jr.
	Richard B. Talley, Jr., P.E.
	Chief Executive Officer

EX-99.7

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;

4. 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 23, 2023	/s/ Ian C. Dundas
	Ian C. Dundas
	President and Chief Executive Officer
	of Enerplus Corporation

EX-99.8

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;

4. 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 23, 2023	/s/ Jodine J. Jenson Labrie
	Jodine J. Jenson Labrie Senior Vice President and Chief Financial Officer of Enerplus Corporation

EX-99.9

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, 2022 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 23, 2023

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.

EX-99.10

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, 2022 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 23, 2023

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.

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2022 shares
Document Information [Line Items]
Entity Central Index Key	0001126874
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Entity File Number	001-15150
Entity Registrant Name	ENERPLUS CORPORATION
Entity Incorporation, State or Country Code	A0
Entity Primary SIC Number	1311
Entity Address, Address Line One	The Dome Tower, 3000
Entity Address, Address Line Two	333 - 7th Avenue S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Country	CA
Entity Address, Postal Zip Code	T2P 2Z1
City Area Code	403
Local Phone Number	298-2200
Title of 12(b) Security	Common Shares
Trading Symbol	ERF
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	217,285,537
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Auditor Name	KPMG LLP
Auditor Location	Calgary, Canada
Auditor Firm ID	85
ICFR Auditor Attestation Flag	true
Document Fiscal Period Focus	FY
Amendment Flag	false
Other Address [Member]
Document Information [Line Items]
Entity Address, Address Line One	US Bank Tower, Suite 2200
Entity Address, Address Line Two	950 - 17th Street
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202-2805
City Area Code	720
Local Phone Number	279-5500
Business Contact [Member]
Document Information [Line Items]
Contact Personnel Name	Enerplus Resources (USA) Inc
Entity Address, Address Line One	US Bank Tower, Suite 2200
Entity Address, Address Line Two	950 - 17th Street
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202-2805
City Area Code	720
Local Phone Number	279-5500

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 38,000	$ 61,348
Accounts receivable	276,590	227,988
Other current assets	56,552	10,956
Derivative financial assets	36,542	5,668
Total Current Assets	407,684	305,960
Property, plant and equipment:
Crude oil and natural gas properties (full cost method)	1,322,904	1,253,505
Other capital assets	10,685	13,887
Property, plant and equipment	1,333,589	1,267,392
Other long-term assets	21,154	9,756
Right-of-use assets	20,556	26,118
Deferred income tax asset	154,998	380,858
Total Assets	1,937,981	1,990,084
Current liabilities
Accounts payable	398,482	367,008
Current portion of long-term debt	80,600	100,600
Derivative financial liabilities	10,421	143,200
Current portion of lease liabilities	13,664	10,618
Total Current Liabilities	503,167	621,426
Long-term debt	178,916	601,171
Asset retirement obligation	114,662	132,814
Derivative financial liabilities		7,098
Lease liabilities	9,262	18,265
Deferred income tax liability	55,361
Total Liabilities	861,368	1,380,774
Shareholders' Equity
Share capital - authorized unlimited common shares, no par value Issued and outstanding: December 31, 2022 - 217 million shares; December 31, 2021 - 244 million shares	2,837,329	3,094,061
Paid-in capital	50,457	50,881
Accumulated deficit	(1,509,832)	(2,238,325)
Accumulated other comprehensive loss	(301,341)	(297,307)
Total Shareholders' Equity	1,076,613	609,310
Total Liabilities & Shareholders' Equity	1,937,981	1,990,084
Commitments and Contingencies

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Share capital
Share capital, shares authorized, unlimited	Unlimited	Unlimited
Share capital, par value (in dollars per share)	$ 0	$ 0
Share capital, shares issued (in shares)	217	244
Share capital, shares outstanding (in shares)	217	244

XML

Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues
Crude oil and natural gas sales	$ 2,353,374	$ 1,482,575	$ 553,739
Type of revenue	Oil and Gas [Member]	Oil and Gas [Member]	Oil and Gas [Member]
Commodity derivative instruments gain/(loss)	$ (197,686)	$ (274,432)	$ 75,742
Total	2,155,688	1,208,143	629,481
Expenses
Production taxes	166,995	101,953	37,417
General and administrative	69,954	56,807	43,097
Depletion, depreciation and accretion	309,367	271,336	218,118
Asset impairment	0	3,420	751,723
Goodwill impairment			149,217
Interest	24,553	27,395	20,737
Foreign exchange (gain)/loss	10,159	(6,908)	1,232
Gain on divestment of assets	(151,937)
Transaction costs and other expense/(income)	(1,360)	(2,487)	4,489
Total	948,090	872,258	1,521,808
Income/(Loss) Before Taxes	1,207,598	335,885	(892,327)
Current income tax expense/(recovery)	28,063	2,689	(10,716)
Deferred income tax expense/(recovery)	265,233	98,755	(188,260)
Net Income/(Loss)	914,302	234,441	(693,351)
Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation	22,507	(6,893)	(2,169)
Foreign exchange gain/(loss) on net investment hedge, net of tax	(26,541)	4,097	1,780
Total Comprehensive Income/(Loss)	$ 910,268	$ 231,645	$ (693,740)
Net Income/(Loss) per Share
Basic (in dollars per share)	$ 3.91	$ 0.93	$ (3.12)
Diluted (in dollars per share)	$ 3.77	$ 0.90	$ (3.12)
Operating
Expenses
Costs of goods sold	$ 365,701	$ 292,433	$ 197,097
Transportation
Expenses
Costs of goods sold	$ 154,658	$ 128,309	$ 98,681

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Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands	Share Capital	Paid-in Capital	Accumulated Deficit	Accumulated Other Comprehensive Income/(Loss)	Total
Balance, beginning of year at Dec. 31, 2019	$ 3,106,875	$ 56,439	$ (1,736,355)	$ (294,122)
Increase (decrease) in equity
Purchase of common shares under Normal Course Issuer Bid	(3,582)		1,775		$ (1,900)
Share-based compensation - tax withholdings settled in cash		(5,567)
Share-based compensation - treasury settled	10,694	(10,694)
Share-based compensation - non-cash		9,204
Cancellation of predecessor shares	(158)		158
Net income/(loss)			(693,351)		(693,351)
Dividends declared			(19,962)		(20,000)
Unrealized gain/(loss) on foreign currency translation				(2,169)	(2,169)
Foreign exchange gain/(loss) on net investment hedge, net of tax				1,780	1,780
Balance, end of year at Dec. 31, 2020	3,113,829	49,382	(2,447,735)	(294,511)	420,965
Increase (decrease) in equity
Purchase of common shares under Normal Course Issuer Bid	(128,686)		5,504		(123,200)
Share-based compensation - tax withholdings settled in cash		(3,551)
Share-based compensation - treasury settled	9,402	(9,402)
Share-based compensation - non-cash		14,452
Issue of shares (net of tax effected issue costs)	99,516
Net income/(loss)			234,441		234,441
Dividends declared			(30,535)		(30,500)
Unrealized gain/(loss) on foreign currency translation				(6,893)	(6,893)
Foreign exchange gain/(loss) on net investment hedge, net of tax				4,097	4,097
Balance, end of year at Dec. 31, 2021	3,094,061	50,881	(2,238,325)	(297,307)	609,310
Increase (decrease) in equity
Purchase of common shares under Normal Course Issuer Bid	(266,694)		(144,212)		(410,900)
Share-based compensation - tax withholdings settled in cash		(13,386)
Share-based compensation - treasury settled	9,962	(9,962)
Share-based compensation - non-cash		22,924
Net income/(loss)			914,302		914,302
Dividends declared			(41,597)		(41,600)
Unrealized gain/(loss) on foreign currency translation				22,507	22,507
Foreign exchange gain/(loss) on net investment hedge, net of tax				(26,541)	(26,541)
Balance, end of year at Dec. 31, 2022	$ 2,837,329	$ 50,457	$ (1,509,832)	$ (301,341)	$ 1,076,613

XML

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Dividends declared
Dividends declared per share (in dollars per share)	$ 0.181	$ 0.121	$ 0.090

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Activities
Net income/(loss)	$ 914,302	$ 234,441	$ (693,351)
Non-cash items add/(deduct):
Depletion, depreciation and accretion	309,367	271,336	218,118
Asset impairment	0	3,420	751,723
Goodwill impairment			149,217
Changes in fair value of derivative instruments	(150,526)	109,536	18,074
Deferred income tax expense/(recovery)	265,233	98,755	(188,260)
Foreign exchange (gain)/loss on debt and working capital	11,217	(8,055)	1,363
Share-based compensation and general and administrative	22,529	13,424	9,508
Other expense/(income)	(4,137)	(4,594)
Amortization of debt issuance costs	1,476	1,093
Translation of U.S. dollar cash held in parent company	(937)	(2,330)	(902)
Gain on divestment of assets	(151,937)
Other expense/(income) reclassified to Investing Activities	13,702	(4,593)
Asset retirement obligation expenditures	(17,401)	(12,951)	(13,275)
Changes in non-cash operating working capital	(39,506)	(94,643)	83,669
Cash flow from/(used in) operating activities	1,173,382	604,839	335,884
Financing Activities
Drawings from/(repayment of) bank credit facilities	(340,650)	400,000
Repayment of senior notes	(100,600)	(81,600)	(81,600)
Debt issue costs	(1,005)	(4,621)
Purchase of common shares under Normal Course Issuer Bid	(410,906)	(123,182)	(1,807)
Proceeds from the issuance of shares		98,339
Share-based compensation - tax withholdings settled in cash	(13,386)	(3,551)	(5,567)
Dividends	(41,597)	(32,284)	(19,897)
Cash flow from/(used in) financing activities	(908,144)	253,101	(108,871)
Investing Activities
Capital and office expenditures	(429,873)	(271,131)	(248,990)
Bruin acquisition		(420,249)
Dunn County acquisition		(305,076)
Canadian divestments	158,033
Property and land acquisitions	(22,515)	(9,846)	(7,491)
Property and land divestments	18,385	108,193	4,456
Other (expense)/income	(13,702)	4,593
Cash flow from/(used in) investing activities	(289,672)	(893,516)	(252,025)
Effect of exchange rate changes on cash and cash equivalents	1,086	6,979	(1,786)
Change in cash and cash equivalents	(23,348)	(28,597)	(26,798)
Cash and cash equivalents, beginning of year	61,348	89,945	116,743
Cash and cash equivalents, end of year	$ 38,000	$ 61,348	$ 89,945

XML

REPORTING ENTITY

12 Months Ended

Dec. 31, 2022

REPORTING ENTITY

REPORTING ENTITY

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 United States (“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’ corporate offices are located in Calgary, Alberta, Canada and Denver, Colorado, United States.

XML

SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2022

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

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 U.S. (“U.S. GAAP”).

i. Reporting and Functional Currency

These Consolidated Financial Statements are presented in U.S. dollars, which is Enerplus’ reporting currency.

The functional currency of the parent entity is Canadian dollars and the functional currency of the U.S. subsidiaries is U.S. dollars. All references to $ or US$ are to U.S. dollars and references to CDN$ are to Canadian dollars. All financial information presented in U.S. and Canadian dollars has been rounded to the nearest thousand unless otherwise indicated.

Subsequent to the year ended December 31, 2022, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars effective January 1, 2023. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a prospective change in functional currency of the parent entity to U.S. dollars, consistent with the functional currency of its U.S. subsidiary.

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 those that relate to: 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, gains on asset divestments, impairment assessment 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 inputs and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Inflation and discount rates impacting various items within the Company’s financial statements are also subject to management estimation. When estimating the present value of future cash flows, the discount rate implicitly considers the potential impacts, if any, due to climate change factors. Enerplus uses the most current information available and exercises judgment in making 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.

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, with limited exceptions, at the acquisition date.

b) Revenue

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.

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. 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, in which case the Company would be the principal and the revenue is recognized on a gross basis. Any associated fees are recorded as an expense. 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.

All references to crude oil and natural gas revenue or production in the Consolidated Financial Statements are net of royalties.

c) Transportation

Enerplus generally sells crude oil and natural gas under two types of agreements which are common in 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).

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 or any other factors, as it is prescribed under U.S. GAAP. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain, and as such, it is difficult to determine the impact on estimated future net cash flows of such a transition.

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 certain circumstances, where the carrying value of the full cost centre exceeds the ceiling test limitation, the Company may seek a temporary waiver from the SEC to exclude certain amounts from the full cost ceiling limitation. The Company must demonstrate that the fair value of the excluded properties clearly exceeds the carrying value.

Under full cost accounting rules, divestments 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 is recognized.

e) Other Capital Assets

Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, and computer equipment. 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.

f) Other Long-term Assets

Other long-term assets include Company-owned line fill in third party pipelines and long-term receivables. Line fill is recorded at lower of cost and net realizable value.

g) Cash and Cash Equivalents

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

h) 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. 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.

i) Asset Retirement Obligations

Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning, reclamation, 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 Depletion, depreciation and accretion and charged against net income in the Consolidated Statements of Income/(Loss).

j) Leases

Enerplus determines at inception, whether a business contract is an operating or finance lease, as defined under U.S. GAAP. 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.

Finance leases are recognized on the commencement date and included in right-of-use (“ROU”) assets and lease liabilities in the Consolidated Balance Sheets. 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 such leases. Lease liabilities are recognized at the present value of the lease payments over the lease term. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is more likely than not that it will exercise those options. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for payments made prior to lease commencement or initial direct costs, if any. When calculating the present value, Enerplus uses the rate implicit in the lease, or uses its incremental borrowing rate for a similar term and risk profile based on the information available at the commencement date.

Lease expense for operating leases is recognized on a straight-line basis over the lease term.

Lease agreements can contain both lease and non-lease components, which are accounted for separately. For certain equipment leases, a portfolio approach is applied to account for the ROU assets and liabilities.

k) 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.

The expected future taxable income considered in the analysis of the valuation allowance is based on cash flows from the proven and probable reserves and other sources of income. 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. Investment tax credits are applied using the flow-through method.

l) 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 and cash equivalents, accounts receivable, accounts payable, bank credit facilities, and marketable securities reported on the Consolidated Balance Sheets approximates their fair value. The fair value of the senior notes and loan receivable are considered a level 2 fair value measurement and details are disclosed in Note 16. 

The Company uses the current expected credit loss model in valuing accounts receivable and loan 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 Statements 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 that is held in the parent entity as a hedge of its net investment in operations for which the U.S. dollar is the functional currency. As a non-derivative financial instrument, it 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 the fair value of the net investment in the U.S. subsidiary. If effective, the unrealized foreign exchange gains and losses arising from the translation of the U.S. denominated debt are recorded in Other Comprehensive Income/(Loss) (“OCI”), net of tax, to the extent the net investment in the U.S. subsidiary supports the U.S. denominated debt.

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).

In connection with the sale of certain Canadian assets during the year, the Company provided a loan to the purchaser. The loan receivable is recorded at its amortized cost basis on the Consolidated Balance Sheets.

Marketable securities are classified as held for trading and carried at fair value based on a level 1 designation, with changes in fair value recorded in Transaction costs and other expense/(income). When the instruments are ultimately sold any gains or losses are recognized in Transaction costs and other expense/(income).

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, 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/(loss). 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.

m) Foreign Currency

i. Foreign currency transactions

Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars in Canada and U.S. dollars in the U.S.) 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/(loss) in the period in which they arise.

ii. Foreign currency translation

For financial statement presentation, assets and liabilities of Enerplus’ Canadian operations, which have a Canadian dollar functional currency, are translated into U.S. 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.

n) 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.

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 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.  

o) 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 outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price.

p) 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.

q) Government Assistance

In 2020, the Alberta, Saskatchewan, and British Columbia provincial governments created programs and provided funding to support the clean-up of inactive or abandoned crude oil and natural gas wells. Enerplus applied for and benefited from these programs in 2022 and 2021. The programs provide funding directly to oil field service contractors engaged by companies to perform abandonment, remediation, and reclamation work. As work is completed, the contractors submit invoices to the provincial government for reimbursement for the pre-approved funding amounts. Enerplus recognizes the assistance as the abandonment, remediation, and reclamation work is completed by the contractor. The benefit of the funding received by the contractor is reflected as a reduction of asset retirement obligation and recorded as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss).

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ACQUISITIONS & DIVESTMENTS

12 Months Ended

Dec. 31, 2022

ACQUISITIONS & DIVESTMENTS

ACQUISITIONS & DIVESTMENTS

3) ACQUISITIONS & DIVESTMENTS

a) Canadian Asset Divestments

On October 31, 2022, the Company completed a disposition of certain Canadian assets to Journey Energy Inc. (“Journey”) for total consideration of $104.4 million (CDN$142.2 million), prior to purchase price adjustments. The total consideration included cash of $59.3 million, 3.0 million common shares in Journey valued at $12.1 million, and a $33.0 million monthly amortizing, interest-bearing secured loan with a 10% fixed interest rate and maturity of October 31, 2024, which Enerplus provided to Journey. After purchase price adjustments and transaction costs, adjusted proceeds were $80.8 million resulting in a $64.5 million gain on asset divestments on the Consolidated Statements of Income/(Loss). The Company reduced the asset retirement obligation by $31.6 million. The Company divested of the common shares in Journey in the fourth quarter of 2022.

On December 19, 2022, the Company completed a disposition of substantially all of the remaining Canadian assets to Surge Energy Inc. (“Surge”) for total consideration of $174.5 million (CDN$238.2 million), prior to purchase price adjustments. The total consideration included cash of $153.9 million and 3.8 million common shares in Surge valued at $20.7 million. After purchase price adjustments and transaction costs, adjusted proceeds were $132.2 million resulting in a $87.4 million gain on asset divestments on the Consolidated Statements of Income/(Loss). The Company reduced the asset retirement obligation by $26.5 million.

At December 31, 2022, the current and long-term portion of the outstanding loan receivable of $17.7 million and $13.4 million, respectively, have been recorded as part of Other current assets and Other long-term assets on the Consolidated Balance Sheets.

At December 31, 2022, the common shares of Surge had a fair value of $23.1 million resulting in an unrealized gain of $2.4 million, recognized in Transaction costs and other expense/(income) on the Consolidated Statements of Income/(Loss). The fair value of the marketable securities has been recorded as part of Other current assets on the Consolidated Balance Sheets.

b) Bruin E&P HoldCo, LLC Acquisition

On March 10, 2021, Enerplus Resources (USA) Corporation, an indirect wholly-owned subsidiary of Enerplus acquired all of the equity interests of Bruin E&P HoldCo, LLC (“Bruin”) for total cash consideration of $465.0 million, subject to certain purchase price adjustments. After purchase price adjustments, the total consideration was $420.2 million. The transaction was accounted for as an acquisition of a business.  

c) Dunn County Acquisition

On April 30, 2021, the Company acquired assets in Dunn County, North Dakota from Hess Bakken Investments II, LLC for total cash consideration of $312.0 million, subject to customary purchase price adjustments. After purchase price adjustments, the purchase consideration including capitalized transaction costs was $306.8 million. The transaction was recorded as an asset acquisition.

d) Sleeping Giant and Russian Creek Divestment

On November 2, 2021, the Company completed a disposition of its interests in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, for total cash consideration of $115.0 million, subject to customary purchase price adjustments. After purchase price adjustments and transaction costs, adjusted proceeds were $107.8 million. Subsequent to December 31, 2022, Enerplus received $2.5 million in contingent consideration and may receive an additional $2.5 million if the WTI oil price averages over $60 per barrel in 2023. The fair value of the contingent consideration has been recorded as part of Other current assets and Other long-term assets.

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ACCOUNTS RECEIVABLE

12 Months Ended

Dec. 31, 2022

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE

4) ACCOUNTS RECEIVABLE

($ thousands)	December 31, 2022		December 31, 2021
Accrued revenue	$	244,494	$	208,160
Accounts receivable – trade		35,019		23,697
Allowance for doubtful accounts		(2,923)		(3,869)
Total accounts receivable, net of allowance for doubtful accounts	$	276,590	$	227,988

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PROPERTY, PLANT AND EQUIPMENT ("PP&E")

12 Months Ended

Dec. 31, 2022

PROPERTY, PLANT AND EQUIPMENT ("PP&E")

PROPERTY, PLANT AND EQUIPMENT ("PP&E")

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

			Accumulated Depletion,
At December 31, 2022			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties(1)	$	13,023,018	$	(11,700,114)	$	1,322,904
Crude oil and natural gas properties – Canadian divestments(2)		(5,808,025)		5,808,025		—
Other capital assets		99,283		(88,598)		10,685
Total PP&E	$	7,314,276	$	(5,980,687)	$	1,333,589

			Accumulated Depletion,
At December 31, 2021			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties(1)	$	13,075,987	$	(11,822,482)	$	1,253,505
Other capital assets		103,355		(89,468)		13,887
Total PP&E	$	13,179,342	$	(11,911,950)	$	1,267,392

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

(2) The Company removed the Canadian cost centre’s historical PP&E balances upon the divestment of the Canadian assets.

Acquisitions:

For the years ended December 31, 2022 and 2021, Enerplus acquired property and land totaling $22.5 million and $857.1 million, respectively. Refer to Note 3 for details regarding the Bruin and Dunn County acquisitions during 2021.

Divestments:

For the years ended December 31, 2022 and 2021, Enerplus disposed of properties for proceeds of $231.4 million and $112.7 million, respectively. Certain asset divestments may result in gains if the divestments cause a significant alteration in the relationship between the cost centre’s capitalized costs and proved reserves. During 2022, Enerplus recognized gains on asset divestments of $151.9 million (2021 and 2020 – nil). Refer to Note 3 for details regarding the divestment of the Canadian assets in 2022 and the Sleeping Giant and Russian Creek assets in 2021.

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IMPAIRMENT

12 Months Ended

Dec. 31, 2022

IMPAIRMENT

IMPAIRMENT

6) IMPAIRMENT

a) Impairment of PP&E

($ thousands)	2022		2021		2020
Crude oil and natural gas properties:
U.S. cost centre	$	—	$	—	$	650,780
Canada cost centre		—		3,420		100,943
Total impairment expense	$	—	$	3,420	$	751,723

No asset impairment was recorded during the year ended December 31, 2022 (2021 – $3.4 million; 2020 – $751.7 million). The primary factors that affect ceiling values include first-day-of-the-month commodity prices, reserves, 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 at December 31, 2022, 2021 and 2020:

	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub Gas		Exchange Rate
Period	$/bbl		CDN$/bbl		$/Mcf		CDN$/US$
2022	$	94.14	$	119.13	$	6.25		0.77
2021		66.55		78.15		3.64		0.80
2020		39.54		45.56		2.00		0.75

b) Impairment of Goodwill

At December 31, 2022 and 2021, there was no goodwill remaining on the Company’s Consolidated Balance Sheets. During the year ended December 31, 2020, Enerplus recorded goodwill impairment of $149.2 million relating to its U.S. reporting unit. This was due to lower commodity prices in 2020, which resulted in a reduction in the fair value of the U.S. reporting unit.

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ACCOUNTS PAYABLE

12 Months Ended

Dec. 31, 2022

ACCOUNTS PAYABLE

ACCOUNTS PAYABLE

7) ACCOUNTS PAYABLE

($ thousands)	December 31, 2022		December 31, 2021
Accrued payables	$	110,267	$	106,222
Accounts payable – trade		288,215		260,786
Total accounts payable	$	398,482	$	367,008

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DEBT

12 Months Ended

Dec. 31, 2022

DEBT

DEBT

8) DEBT

($ thousands)	December 31, 2022		December 31, 2021
Current:
Senior notes	$	80,600	$	100,600
Long-term:
Bank credit facilities		56,316		397,971
Senior notes		122,600		203,200
Total debt	$	259,516	$	701,771

Bank Credit Facilities

In February 2022, Enerplus converted its senior unsecured, covenant-based, $400 million term loan maturing on March 10, 2024 into a revolving bank credit facility with no other amendments. In November 2022, Enerplus converted this $400 million revolving bank credit facility to a $365 million sustainability-linked lending (“SLL”) bank credit facility and extended the maturity to October 31, 2025. The $365 million SLL bank credit facility has the same targets as Enerplus’ $900 million SLL bank credit facility. There were no other significant amendments or additions to the agreement’s terms or covenants. Debt issuance costs were netted against the debt on issuance and are being amortized over the three-year term with $1.5 million of unamortized debt issuance costs remaining at December 31, 2022.

Enerplus also has a senior unsecured, covenant-based, $900 million SLL bank credit facility, which was renewed in November 2022, with $50 million maturing on October 31, 2025, and $850 million maturing on October 31, 2026. There were no other significant amendments or additions to the agreement’s terms or covenants. Debt issuance costs in relation to the SLL bank credit facility were netted against the debt on issuance and are being amortized over the four year term with $1.7 million of unamortized debt issuance costs remaining at December 31, 2022.  

The SLL bank credit facilities incorporate environmental, social and governance (“ESG”)-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus’ sustainability performance targets (“SPT”) are exceeded or missed. The SPTs are based on the following ESG goals of the Company:

● GHG Emissions: continuous progress toward Enerplus’ stated goal of a 35% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2021 as a baseline and measurement based on Enerplus’ annual internal targets;

● Water Management: achieve a 50% reduction in freshwater usage in corporate well completions by 2025 or earlier compared to 2019; and

● Health & Safety: achieve and maintain a 25% reduction in the Company’s Lost Time Injury Frequency, based on a trailing 3-year average, relative to a 2019 baseline.

For the year ended December 31, 2022, total amortization of debt issuance costs amounted to $1.5 million (December 31, 2021 – $1.1 million).

Senior Notes

During 2022, Enerplus made a $21.0 million principal repayment on its 2014 senior notes. In addition, Enerplus made its third $59.6 million principal repayment and a $20.0 million bullet payment on its 2012 senior notes.

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

				Original	Remaining
			Coupon	Principal	Principal
Issue Date	Interest Payment Dates	Principal Repayment	Rate	($ thousands)	($ thousands)
September 3, 2014	March 3 and Sept 3	4 equal annual installments beginning September 3, 2023	3.79%	$200,000	$84,000
May 15, 2012	May 15 and Nov 15	2 equal annual installments beginning May 15, 2023	4.40%	$355,000	$119,200
		Total carrying value at December 31, 2022			$ 203,200

Capital Management

Enerplus' capital consists of cash and cash equivalents, debt and shareholders' equity. The Company’s objective for managing capital is to prioritize balance sheet strength while maintaining flexibility to repay debt, fund sustaining capital, return capital to shareholders or fund future production growth. Capital management measures are useful to investors and securities analysts in analyzing operating and financial performance, leverage, and liquidity. Enerplus’ key capital management measures are as follows:

a) Net Debt

Enerplus calculates net debt as current and long-term debt associated with senior notes plus any outstanding bank credit facility balances, minus cash and cash equivalents.

($ thousands)	December 31, 2022		December 31, 2021
Current portion of long-term debt	$	80,600	$	100,600
Long-term debt		178,916		601,171
Total debt	$	259,516	$	701,771
Less: Cash and cash equivalents		(38,000)		(61,348)
Net debt	$	221,516	$	640,423

b) Adjusted funds flow

Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.

($ thousands)		2022		2021		2020
Cash flow from/(used in) operating activities	$	1,173,382	$	604,839	$	335,884
Asset retirement obligation settlements		17,401		12,951		13,275
Changes in non-cash operating working capital		39,506		94,643		(83,669)
Adjusted funds flow	$	1,230,289	$	712,433	$	265,490

c) Net debt to adjusted funds flow ratio

The net debt to adjusted funds flow ratio is calculated as net debt divided by a trailing twelve months of adjusted funds flow.

($thousands)	December 31, 2022		December 31, 2021
Net debt	$	221,516	$	640,423
Trailing adjusted funds flow		1,230,289		712,433
Net debt to adjusted funds flow ratio	$	0.2x	$	0.9x

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ASSET RETIREMENT OBLIGATION ("ARO")

12 Months Ended

Dec. 31, 2022

ASSET RETIREMENT OBLIGATION ("ARO")

ASSET RETIREMENT OBLIGATION ("ARO")

9) ASSET RETIREMENT OBLIGATION (“ARO”)

($ thousands)	December 31, 2022		December 31, 2021
Balance, beginning of year	$	132,814	$	102,325
Change in estimates		48,419		26,586
Property acquisition and development activity		3,985		1,304
Bruin acquisition (Note 3)		—		21,964
Dunn County acquisition (Note 3)		—		5,880
Divestments (Note 3)		(58,284)		(13,525)
Settlements		(17,401)		(12,951)
Government assistance		(1,744)		(4,594)
Accretion expense		6,873		5,825
Balance, end of year	$	114,662	$	132,814

Enerplus has estimated the present value of its asset retirement obligation to be $114.7 million at December 31, 2022 based on a total undiscounted, uninflated liability of $262.4 million (December 31, 2021 – $132.8 million and $303.3 million, respectively). Enerplus’ asset retirement obligation expenditures are mainly expected to be incurred between 2023 – 2034 and 2037 – 2053.

Enerplus benefited from provincial government assistance to support the clean-up of inactive or abandoned crude oil and natural gas wells. These programs provide funding directly to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. For the year ended December 31, 2022, Enerplus benefited from $1.7 million (2021 – $4.6 million, 2020 – nil) in government assistance, which has been recorded as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss).

During 2022, Enerplus recognized $13.1 million as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss) to fund abandonment and reclamation obligation requirements on previously disposed of assets (2021 and 2020 – nil).

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LEASES

12 Months Ended

Dec. 31, 2022

LEASES

LEASES

10) LEASES

The Company has entered into various lease contracts 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 Sheets. Such items are charged to operating expenses or general and administrative expenses, as appropriate, in the Consolidated Statements of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with U.S. GAAP.

($ thousands)	December 31, 2022		December 31, 2021
Assets
Operating right-of-use assets	$	20,556	$	26,118
Liabilities
Current operating lease liabilities	$	13,664	$	10,618
Non-current operating lease liabilities		9,262		18,265
Total lease liabilities	$	22,926	$	28,883
Weighted average remaining lease term (years)
Operating leases		2.4		3.3
Weighted average discount rate
Operating leases		3.7%		3.4%

The Company’s lease contract expenditures/(income) for the years ended December 31, 2022 and 2021 are as follows:

($ thousands)	2022		2021
Operating lease cost	$	12,409	$	11,378
Variable lease cost		3,847		633
Short-term lease cost		7,163		3,469
Sublease income		(1,091)		(1,083)
Total	$	22,328	$	14,397

Variable lease payments are determined through analysis of day rate fees under applicable rig contracts. The amounts in the table above are recorded as part of general and administrative or operating expenses or property, plant, and equipment depending on the nature of the contract to which they relate. Although Enerplus has various leases containing extensions and/or termination options, none were determined to be reasonably certain to be exercised. As a result, none of these options are recognized as part of the ROU assets or lease liabilities at December 31, 2022 or 2021.

Maturities of lease liabilities, all of which are classified as operating leases at December 31, 2022, are as follows:

($ thousands)	Operating Leases
2023	$	14,278
2024		6,475
2025		1,099
2026		966
2027		988
After 2027		165
Total lease payments	$	23,971
Less imputed interest		(1,045)
Total discounted lease payments	$	22,926
Current portion of lease liabilities	$	13,664
Non-current portion of lease liabilities	$	9,262

Supplemental information related to leases is as follows:

($ thousands)	2022			2021
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases	$	10,552	$	11,571
Right-of-use assets obtained/(terminated) in exchange for lease liabilities:
Operating leases	$	5,651	$	10,030

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CRUDE OIL AND NATURAL GAS SALES

12 Months Ended

Dec. 31, 2022

CRUDE OIL AND NATURAL GAS SALES

CRUDE OIL AND NATURAL GAS SALES

11) CRUDE OIL AND NATURAL GAS SALES

Crude oil and natural gas sales by country and by product for the years ended December 31, 2022, 2021 and 2020 are as follows:

2022						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	2,205,876	$	1,646,453	$	455,678	$	103,731	$	14
Canada		147,498		131,283		10,918		4,760		537
Total	$	2,353,374	$	1,777,736	$	466,596	$	108,491	$	551

2021						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	1,355,255	$	1,055,748	$	219,552	$	79,930	$	25
Canada		127,320		111,070		11,127		4,348		775
Total	$	1,482,575	$	1,166,818	$	230,679	$	84,278	$	800

2020						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	480,822	$	380,074	$	92,453	$	8,182	$	113
Canada		72,917		59,642		9,239		2,591		1,445
Total	$	553,739	$	439,716	$	101,692	$	10,773	$	1,558

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

(2) Includes third party processing income.

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GENERAL AND ADMINISTRATIVE EXPENSE

12 Months Ended

Dec. 31, 2022

GENERAL AND ADMINISTRATIVE EXPENSE

GENERAL AND ADMINISTRATIVE EXPENSE

12) GENERAL AND ADMINISTRATIVE EXPENSE

($ thousands)	2022		2021		2020
General and administrative expense excluding share-based compensation(1)	$	42,374	$	38,013	$	33,347
Share-based compensation expense		27,580		18,794		9,750
General and administrative expense	$	69,954	$	56,807	$	43,097

(1) Includes non-cash lease credit of $395 in 2022, $365 in 2021, $212 in 2020.

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FOREIGN EXCHANGE

12 Months Ended

Dec. 31, 2022

FOREIGN EXCHANGE

FOREIGN EXCHANGE

13) FOREIGN EXCHANGE

($ thousands)	2022		2021		2020
Realized:
Foreign exchange (gain)/loss	$	(121)	$	3,477	$	771
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company		(937)		(2,330)		(902)
Unrealized:
Foreign exchange (gain)/loss on U.S. dollar working capital in parent company		11,217		(8,055)		1,363
Foreign exchange (gain)/loss	$	10,159	$	(6,908)	$	1,232

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INCOME TAXES

12 Months Ended

Dec. 31, 2022

INCOME TAXES

INCOME TAXES

14) INCOME TAXES

Enerplus’ provision for income tax is as follows:

($ thousands)	2022		2021		2020
Current tax
United States	$	28,063	$	2,700	$	(10,716)
Canada		—		(11)		—
Current tax expense/(recovery)		28,063		2,689		(10,716)
Deferred tax
United States	$	217,943	$	148,920	$	(167,835)
Canada		47,290		(50,165)		(20,425)
Deferred tax expense/(recovery)		265,233		98,755		(188,260)
Income tax expense/(recovery)	$	293,296	$	101,444	$	(198,976)

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

($ thousands)	2022		2021		2020
Income/(loss) before taxes
United States	$	966,646	$	544,464	$	(877,406)
Canada		240,952		(208,579)		(14,921)
Total income/(loss) before taxes		1,207,598		335,885		(892,327)
Canadian statutory rate		23%		24%		24%
Expected income tax expense/(recovery)	$	277,748	$	80,612		(214,158)
Impact on taxes resulting from:
Foreign and statutory rate differences	$	35,636	$	19,297	$	(27,918)
Investment tax credit		(14,245)		—		(9,639)
Non-taxable capital (gains)/losses		(184)		(105)		14,341
Change in valuation allowance		291		(560)		(25,918)
Goodwill impairment, share-based compensation and other		(5,950)		2,200		64,317
Income tax expense/(recovery)	$	293,296	$	101,444	$	(198,976)

The deferred income tax asset/(liability) consists of the following:

At December 31 ($ thousands)	2022		2021
Canadian deferred income tax asset/(liability)
Property, plant and equipment	$	40,207	$	125,311
Tax loss carry-forwards and other credits		101,909		40,891
Capital loss carryforwards and other capital items		101,078		107,681
Asset retirement obligation		11,368		17,368
Derivative financial instruments		(6,578)		28,907
Other		6,442		10,966
Valuation allowance		(99,428)		(112,847)
Canadian deferred income tax asset/(liability)		154,998		218,276
United States deferred income tax asset/(liability)
Property, plant and equipment	$	(77,868)	$	(45,824)
Tax loss carry-forwards and other credits		1,785		200,057
Asset retirement obligation		15,645		15,528
Other		5,077		(7,180)
United States deferred income tax asset/(liability)		(55,361)		162,582
Total deferred income tax asset/(liability)	$	99,637	$	380,858

Loss carry-forwards available for tax reporting purposes:

At December 31 ($ thousands)	2022		Expiration Date
Canada Federal
Non-capital losses	$	365,000	2031-2042

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

($ thousands)	2022		2021		2020
Balance, beginning of year	$	15,485	$	15,485	$	—
Increase – tax positions in prior periods		—		—		15,485
Balance, end of year	$	15,485	$	15,485	$	15,485

If recognized, all of Enerplus’ unrecognized tax benefits at December 31, 2022 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
United States – Federal	2019-2022
Canada – Federal	2018-2022

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.

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SHAREHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2022

SHAREHOLDERS' EQUITY

SHAREHOLDERS' EQUITY

15) SHAREHOLDERS’ EQUITY

a) Share Capital

	2022			2021			2020
(thousands)	Shares	Amount		Shares	Amount		Shares	Amount
Balance, beginning of year	243,852	$	3,094,061	222,548	$	3,113,829	221,744	$	3,106,875
Issued/(Purchased) for cash:
Purchase of common shares under Normal Course Issuer Bid	(27,925)		(266,694)	(12,898)		(128,686)	(340)		(3,582)
Issue of shares (net of tax effected issue costs)	—		—	33,062		99,516	—		—
Non-cash:
Share-based compensation – treasury settled(1)	1,358		9,962	1,140		9,402	1,160		10,694
Cancellation of predecessor shares	—		—	—		—	(16)		(158)
Balance, end of year	217,285	$	2,837,329	243,852	$	3,094,061	222,548	$	3,113,829

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

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

For the year ended December 31, 2022, Enerplus declared dividends of $0.181 per weighted average common share totaling $41.6 million (2021 – $0.121 per share and $30.5 million; 2020 – $0.090 per share and $20.0 million).  Subsequent to December 31, 2022, the Board of Directors approved a first quarter dividend of $0.055 per share, to be paid in March 2023.

On August 16, 2022 Enerplus renewed its Normal Course Issuer Bid (“NCIB”) to purchase up to 10% of the public float (within the meaning under Toronto Stock Exchange rules) during a 12-month period. Enerplus completed its previous NCIB in July 2022. For the year ended December 31, 2022, 27,924,842 common shares were repurchased and cancelled under the NCIB at an average price of $14.71 per share, for total consideration of $410.9 million. Of the amount paid, $266.7 million was charged to share capital and $144.2 million was added to accumulated deficit. At December 31, 2022, 7,883,479 common shares are available for repurchase under the current NCIB.

For the year ended December 31, 2021, the Company repurchased 12,897,721 common shares under the NCIB at an average price of $9.55 per share, for total consideration of $123.2 million. Of the amount paid, $128.7 million was charged to share capital and $5.5 million was credited to accumulated deficit.

For the year ended December 31, 2020, the Company repurchased 340,434 common shares under the former NCIB at an average price of $5.63 per share, for total consideration of $1.9 million. Of the amount paid, $3.6 million was charged to share capital and $1.7 million was credited to accumulated deficit.

Subsequent to December 31, 2022 and up to and including February 22, 2023, the Company repurchased 1,420,927 common shares under the current NCIB at an average price of $16.65 per share, for total consideration of $23.7 million.

For the year ended December 31, 2021, Enerplus issued 33,062,500 common shares at a price of CDN$4.00 per common share  for gross proceeds of $103.4 million (net $99.5 million, after $5.1 million in issue costs, net of $1.2 million in tax) pursuant to a bought deal prospectus offering under its base shelf prospectus.

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)	2022		2021		2020
Cash:
Long-term incentive plans (recovery)/expense	$	5,664	$	6,875	$	(934)
Non-Cash:
Long-term incentive plans expense		22,924		13,789		9,720
Equity swap (gain)/loss		(1,008)		(1,870)		964
Share-based compensation expense	$	27,580	$	18,794	$	9,750

LTI Plans

The following table summarizes the PSU, RSU, DSU and DRSU activity for the year ended December 31, 2022:

For the year ended December 31, 2022	Cash-settled LTI Plans	Equity-settled LTI Plans		Total
(thousands of units)	DSU/DRSU	PSU(1)	RSU
Balance, beginning of year	589	3,981	3,065	7,635
Granted	89	809	837	1,735
Vested	(45)	(1,030)	(1,316)	(2,391)
Forfeited	—	(71)	(265)	(336)
Balance, end of year	633	3,689	2,321	6,643

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

Cash-settled LTI Plans

For the year ended December 31, 2022, the Company recorded a cash share-based compensation expense of $5.7 million (2021 – expense of $6.9 million; 2020 – recovery of $0.9 million).

At December 31, 2022, a liability of $11.1 million (December 31, 2021 – $6.3 million) with respect to the Director DSU and DRSU Plans 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 as 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, 2022 ($ thousands, except for years)	PSU(1)		RSU		Total
Cumulative recognized share-based compensation expense	$	21,616	$	10,368	$	31,984
Unrecognized share-based compensation expense		11,815		4,136		15,951
Fair value	$	33,431	$	14,504	$	47,935
Weighted-average remaining contractual term (years)		1.2		0.9

(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, 2022,  $13.4 million (2021 – $3.6 million; 2020 – $5.6 million) in cash withholding taxes were paid.

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

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

(thousands, except per share amounts)	2022		2021		2020
Net income/(loss)	$	914,302	$	234,441	$	(693,351)
Weighted average shares outstanding – Basic		233,946		251,909		222,503
Dilutive impact of share-based compensation(1)		8,727		7,942		—
Weighted average shares outstanding – Diluted		242,673		259,851		222,503
Net income/(loss) per share
Basic	$	3.91	$	0.93	$	(3.12)
Diluted	$	3.77	$	0.90	$	(3.12)

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

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

12 Months Ended

Dec. 31, 2022

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

16) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At December 31, 2022, the carrying value of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term nature of these instruments. The fair values of the bank credit facilities approximate their carrying values as they bear interest at floating rates and the credit spread approximates current market rates.

At December 31, 2022, the senior notes had a carrying value of $203.2 million and a fair value of $189.5 million (December 31, 2021 – $303.8 million and $304.1 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.

At December 31, 2022, the loan receivable had a carrying value of $31.1 million and a fair value of $31.6 million (December 31, 2022 – nil). The fair value of the loan receivable is estimated based on the amount that Enerplus would receive from a third party to assume the loan, including the difference between the coupon rate and the period end market rate for loan receivables of similar terms and credit risk.

The fair value of marketable securities are considered level 1 fair value measurements, while the derivative contracts, senior notes, bank credit facilities and loan receivable are considered level 2 fair value measurements. 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 table summarizes the change in fair value associated with equity and commodity contracts for the respective years:

							Income
Gain/(Loss) ($ thousands)	2022		2021		2020		Statement Presentation
Equity Swaps	$	1,008	$	1,870	$	(964)	G&A expense
Commodity Contracts:
Crude oil		125,842		(111,655)		(19,891)	Commodity derivative
Natural gas		23,676		249		2,781	instruments
Total Unrealized Gain/(Loss)	$	150,526	$	(109,536)	$	(18,074)

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

($ thousands)	2022		2021		2020
Unrealized change in fair value gain/(loss)	$	149,518	$	(111,406)	$	(17,110)
Net realized cash gain/(loss)		(347,204)		(163,026)		92,852
Commodity contracts gain/(loss)	$	(197,686)	$	(274,432)	$	75,742

The following table summarizes the presentation of fair values on the Consolidated Balance Sheets:

	December 31, 2022				December 31, 2021
	Assets		Liabilities			Assets		Liabilities
($ thousands)	Current		Current			Current		Current		Long-term
Equity Swaps	$	—	$	—		$	—	$	969	$	—
Commodity Contracts:
Crude oil		9,834		10,421			1,771		141,364		7,098
Natural gas		26,708		—			3,897		867		—
Total	$	36,542	$	10,421		$	5,668	$	143,200	$	7,098

The fair value of commodity contracts and the equity swaps is estimated based on commodity and option pricing models that incorporate various factors including forecasted commodity prices, volatility and the credit risk of the entities party to the contract. Changes and variability 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.

At December 31, 2022, the fair value of Enerplus’ commodity contracts totaled a net asset of $26.1 million (December 31, 2021 – net liability $143.7 million). This balance included a liability of $10.1 million (December 31, 2021 – $40.2 million) related to Bruin contracts, with $2.7 million (December 31, 2021 – $22.8 million) remaining from the original $76.4 million liability acquired from Bruin on March 10, 2021.

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, liquidity risk, and the risks associated with environmental/climate change risk, social and governance regulation, and compliance.  

i) Market Risk

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

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.

The following tables summarize Enerplus’ price risk management positions at February 22, 2023:

Crude Oil Instruments:

Instrument Type(1)(2)
	Jan 1, 2023 - Jun 30, 2023		Jul 1, 2023 - Oct 31, 2023		Nov 1, 2023 - Dec 31, 2023
	bbls/day	$/bbl	bbls/day	$/bbl	bbls/day	$/bbl
WTI Purchased Put	15,000	79.33	5,000	85.00	5,000	85.00
WTI Sold Put	15,000	61.67	5,000	65.00	5,000	65.00
WTI Sold Call	15,000	114.31	5,000	128.16	5,000	128.16
Brent – WTI Spread	10,000	5.47	10,000	5.47	10,000	5.47
WTI Purchased Swap	250	64.85	250	64.85	—	—
WTI Sold Swap(3)	250	42.10	250	42.10	—	—
WTI Purchased Put(3)	2,000	5.00	2,000	5.00	2,000	5.00
WTI Sold Call(3)	2,000	75.00	2,000	75.00	2,000	75.00

(1) The total average deferred premium spent on the Company’s outstanding crude oil contracts is $1.25/bbl from January 1, 2023 – December 31, 2023.

(2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes.

(3) Outstanding commodity derivative instruments acquired as part of the Bruin Acquisition.

Natural Gas Instruments:

Instrument Type(1)	Jan 1, 2023 – Jan 31, 2023		Feb 1, 2023 – Feb 28, 2023		Mar 1, 2023 – Mar 31, 2023
	MMcf/day	$/Mcf	MMcf/day	$/Mcf	MMcf/day	$/Mcf
NYMEX Purchased Swap	—	—	120.0	3.10	120.0	2.44
NYMEX Purchased Put	120.0	6.27	120.0	6.27	120.0	6.27
NYMEX Sold Call	120.0	18.17	120.0	18.17	120.0	18.17
TZ6 NNY Basis Swap	—	—	—	—	12.5	0.41

(1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

Instrument Type(1)	Apr 1, 2023 – Oct 31, 2023
	MMcf/day	$/Mcf
NYMEX Purchased Put	50.0	4.05
NYMEX Sold Call	50.0	7.00

(1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

Foreign Exchange Risk & Net Investment Hedge:

Enerplus is exposed to foreign exchange risk as it relates to certain activity transacted in Canadian or United States dollars. Enerplus has a U.S. dollar reporting currency, however Enerplus’ parent company has a Canadian functional currency until December 31, 2022. Activity in the Canadian parent company that is transacted in U.S. dollars results in realized and unrealized foreign exchange gains and losses and is recorded on the Consolidated Statements of Income/(Loss).

Enerplus may designate certain U.S. dollar denominated debt held in the parent entity as a hedge of its net investment in its U.S. subsidiary, which has a U.S. dollar functional currency. 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 by the cumulative translation gain or loss on the net investment in the foreign subsidiary. At December 31, 2022, $203.2 million of senior notes and the $56.3 million drawn on the bank credit facilities were designated as net investment hedges (2021 – $303.8 million of senior notes and $400 million of the term loan). For the year ended December 31, 2022, Other Comprehensive Income/(Loss) included an unrealized loss of $26.5 million on Enerplus’ U.S. denominated senior notes and bank credit facilities (2021 – $4.1 million gain and 2020 – $1.8 million gain).

Interest Rate Risk:

The Company’s senior notes bear interest at fixed rates while the bank credit facilities bear interest at floating rates.  At December 31, 2022, approximately 78% of Enerplus’ debt was based on fixed interest rates and 22% on floating interest rates (December 31, 2021 – 43% fixed and 57% floating), with weighted average interest rates of 4.2% and 5.7%, respectively (December 31, 2021 – 4.2% and 1.9%, respectively). At December 31, 2022 and 2021, Enerplus did not have any interest rate derivatives outstanding.

Equity Price Risk:

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 15. The Company may enter into various equity swaps to fix the future settlement cost on a portion of its cash settled LTI plans. At December 31, 2022, Enerplus did not have any equity swaps outstanding.

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, divestments and financial counterparty receivables. Enerplus has appropriate policies and procedures in place to manage its credit risk; however, given the volatility in commodity prices, Enerplus is subject to an increased risk of financial loss due to non-performance or insolvency of its counterparties.

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.

The Company’s maximum credit exposure consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At December 31, 2022, approximately 90% of Enerplus’ marketing receivables were with companies considered investment grade (December 31, 2021 – 83%).

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, 2022 was $2.9 million (December 31, 2021 – $3.9 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 crude 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, 2022, Enerplus was in full compliance with all covenants under the bank credit facilities and outstanding senior notes. If the Company breaches or anticipates breaching its covenants, the Company may be required to repay, refinance, or renegotiate the terms of the debt.

iv) Climate Change Risk

The following provides certain considerations as to the impact of climate change on the amounts recorded in the financial statements for the year ended December 31, 2022. The below is not a comprehensive list or analysis of all climate change impacts and risks. In addition, the focus is with respect to the impact of climate change on amounts recognized in the Company’s financial statements as at and for the year ended December 31, 2022.

Changing regulation

Emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. The Canadian Securities Administrators have issued proposed National Instrument 51-107 Disclosure of Climate-related Matters and the U.S. Securities and Exchange Commission has issued proposed Rule 33-11042 The Enhancement and Standardization of Climate-Related Disclosures for Investors. The cost to comply with these standards, and others that may be developed or evolve over time, has not been quantified.

Impact of climate events and change on amounts recorded in the 2022 financial statements

Reserves:

The Company engages a third party external reserve engineer to review the reserve report. Enerplus considers the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in its assessment of economic recovery of crude oil and natural gas reserves. The reserve report includes anticipated impacts from emissions related taxes, most notably the reserve report includes estimated carbon tax related to the Company’s operations.

Ceiling test:

Given the prescriptive nature of the ceiling test and depletion calculations, climate change risk is only considered in the determination of reserves, which will impact the ceiling test and depletion calculations. At December 31, 2022, no impairment was recorded as a result of the ceiling test completed. See Note 6 for further detail.

Expenditures on property, plant and equipment:

The Company incurs capital expenditures related to emissions reduction initiatives. The extent of spending on projects directly linked to reducing the climate impact of the Company’s operations will vary, however, management anticipates funding future projects through cash flow from operations and bank credit facilities.

Current assets and current liabilities:

These amounts are short term in nature and management is not aware of any material impacts on these items related to climate change and climate events. The Company did not experience material credit losses on its accounts receivable during 2022.

Access to Capital:

There is risk that access to capital may be restricted to the oil and gas industry. Management plans to continue to monitor and adjust the capital structure where necessary. At December 31, 2022, Enerplus had two SLL bank credit facilities with three sustainability performance targets. See Note 8 for further detail.  

Physical effects of climate events (i.e. fire, flood, extreme weather) on the financial results

The Company’s financial results for 2022 were not materially impacted by a climate event.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2022

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

17) COMMITMENTS AND CONTINGENCIES

a) Commitments

Enerplus has the following minimum annual commitments, excluding operating leases which are recorded in the lease liability (see Note 10):

			Minimum Annual Commitment Each Year
($ thousands)		Total	2023		2024		2025		2026		2027		Thereafter
Senior notes(1)	$	203,200	$	80,600	$	80,600	$	21,000	$	21,000	$	—	$	—
Transportation commitments		487,604		71,329		72,598		73,428		73,975		61,852		134,422
Service workover rigs commitments		7,884		7,884		—		—		—		—		—
Purchase commitments		2,100		2,100		—		—		—		—		—
Total commitments(2)	$	700,788	$	161,913	$	153,198	$	94,428	$	94,975	$	61,852	$	134,422

(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.

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.

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GEOGRAPHICAL INFORMATION

12 Months Ended

Dec. 31, 2022

GEOGRAPHICAL INFORMATION

GEOGRAPHICAL INFORMATION

18) GEOGRAPHICAL INFORMATION

As at and for the year ended December 31, 2022 ($ thousands)	U.S.		Canada		Total
Crude oil and natural gas sales	$	2,205,876	$	147,498	$	2,353,374
Depletion, depreciation and accretion		286,438		22,929		309,367
Property, plant and equipment		1,329,545		4,044		1,333,589
Deferred income tax asset		—		154,998		154,998
Deferred income tax liability		55,361		—		55,361

As at and for the year ended December 31, 2021 ($ thousands)		U.S.		Canada		Total
Crude oil and natural gas sales	$	1,355,255	$	127,320	$	1,482,575
Depletion, depreciation and accretion		246,949		24,387		271,336
Property, plant and equipment		1,179,070		88,322		1,267,392
Deferred income tax asset		162,582		218,276		380,858

As at and for the year ended December 31, 2020 ($ thousands)		U.S.		Canada		Total
Crude oil and natural gas sales	$	480,822	$	72,917	$	553,739
Depletion, depreciation and accretion		183,226		34,892		218,118
Property, plant and equipment		375,634		88,167		463,801
Deferred income tax asset		311,502		165,512		477,014

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SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2022

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

19) SUPPLEMENTAL CASH FLOW INFORMATION

a) Changes in Non-Cash Operating Working Capital

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Accounts receivable	$	(45,837)	$	(144,413)	$	84,685
Other assets		(2,442)		(7,583)		(3,333)
Accounts payable – operating		8,773		57,353		2,317
Non-cash operating activities	$	(39,506)	$	(94,643)	$	83,669

b) Changes in Non-Cash Financing Working Capital

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Dividends payable	$	—	$	(1,749)	$	65
Non-cash financing activities	$	—	$	(1,749)	$	65

c) Changes in Non-Cash Investing Working Capital  

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Accounts payable – investing(1)	$	3,420	$	32,793	$	(28,390)

(1) 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.

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Settlement on divestment'(1)	$	(13,053)	$	—	$	—

(1) Relates to funding abandonment and reclamation obligation requirements on previously disposed assets. Refer to Note 9.

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Loan receivable	$	(31,172)	$	—	$	—
Marketable securities		(20,654)		—		—
Accounts receivable		(3,128)		—		—
Non-cash working capital – Canadian divestments(1)	$	(54,954)	$	—	$	—

(1) Refer to Note 3.

d) Cash Income taxes and Interest payments

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Income taxes paid/(received)	$	26,061	$	5,500	$	(42,716)
Interest paid	$	24,399	$	25,808	$	21,276

e) Other

During the year ended December 31, 2021, Enerplus received a $4.6 million distribution associated with a privately held investment. This distribution was recorded within Transaction costs and other expense/(income) on the Consolidated Statements of Income/(Loss), and reflected as an investing activity in the Consolidated Statements of Cash Flows.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2022

SIGNIFICANT ACCOUNTING POLICIES

Basis of Preparation

a) Basis of Preparation

Enerplus’ Consolidated Financial Statements have been prepared by management in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”).

i. Reporting and Functional Currency

These Consolidated Financial Statements are presented in U.S. dollars, which is Enerplus’ reporting currency.

The functional currency of the parent entity is Canadian dollars and the functional currency of the U.S. subsidiaries is U.S. dollars. All references to $ or US$ are to U.S. dollars and references to CDN$ are to Canadian dollars. All financial information presented in U.S. and Canadian dollars has been rounded to the nearest thousand unless otherwise indicated.

Subsequent to the year ended December 31, 2022, the functional currency of the parent entity changed from Canadian dollars to U.S. dollars effective January 1, 2023. This was the result of a gradual change in the primary economic environment in which the entity operates, culminating in the sale of Enerplus’ remaining Canadian operating assets at the end of 2022. This has triggered a prospective change in functional currency of the parent entity to U.S. dollars, consistent with the functional currency of its U.S. subsidiary.

Use of Estimates

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 those that relate to: 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, gains on asset divestments, impairment assessment 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 inputs and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Inflation and discount rates impacting various items within the Company’s financial statements are also subject to management estimation. When estimating the present value of future cash flows, the discount rate implicitly considers the potential impacts, if any, due to climate change factors. Enerplus uses the most current information available and exercises judgment in making 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.

Basis of Consolidation

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.

Business Combinations

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, with limited exceptions, at the acquisition date.

Revenue

b) Revenue

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.

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. 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, in which case the Company would be the principal and the revenue is recognized on a gross basis. Any associated fees are recorded as an expense. 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.

All references to crude oil and natural gas revenue or production in the Consolidated Financial Statements are net of royalties.

Transportation

c) Transportation

Enerplus generally sells crude oil and natural gas under two types of agreements which are common in 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).

Crude Oil and Natural Gas Properties

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 or any other factors, as it is prescribed under U.S. GAAP. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain, and as such, it is difficult to determine the impact on estimated future net cash flows of such a transition.

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 certain circumstances, where the carrying value of the full cost centre exceeds the ceiling test limitation, the Company may seek a temporary waiver from the SEC to exclude certain amounts from the full cost ceiling limitation. The Company must demonstrate that the fair value of the excluded properties clearly exceeds the carrying value.

Under full cost accounting rules, divestments 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 is recognized.

Other Capital Assets

e) Other Capital Assets

Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, and computer equipment. 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.

f) Other Long-term Assets

Other long-term assets include Company-owned line fill in third party pipelines and long-term receivables. Line fill is recorded at lower of cost and net realizable value.

Cash and Cash Equivalents

g) Cash and Cash Equivalents

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

Goodwill

h) 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. 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.

Asset Retirement Obligations

i) Asset Retirement Obligations

Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning, reclamation, 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 Depletion, depreciation and accretion and charged against net income in the Consolidated Statements of Income/(Loss).

Leases

j) Leases

Enerplus determines at inception, whether a business contract is an operating or finance lease, as defined under U.S. GAAP. 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.

Finance leases are recognized on the commencement date and included in right-of-use (“ROU”) assets and lease liabilities in the Consolidated Balance Sheets. 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 such leases. Lease liabilities are recognized at the present value of the lease payments over the lease term. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is more likely than not that it will exercise those options. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for payments made prior to lease commencement or initial direct costs, if any. When calculating the present value, Enerplus uses the rate implicit in the lease, or uses its incremental borrowing rate for a similar term and risk profile based on the information available at the commencement date.

Lease expense for operating leases is recognized on a straight-line basis over the lease term.

Lease agreements can contain both lease and non-lease components, which are accounted for separately. For certain equipment leases, a portfolio approach is applied to account for the ROU assets and liabilities.

Income Tax

k) 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.

The expected future taxable income considered in the analysis of the valuation allowance is based on cash flows from the proven and probable reserves and other sources of income. 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. Investment tax credits are applied using the flow-through method.

Financial Instruments

l) 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 and cash equivalents, accounts receivable, accounts payable, bank credit facilities, and marketable securities reported on the Consolidated Balance Sheets approximates their fair value. The fair value of the senior notes and loan receivable are considered a level 2 fair value measurement and details are disclosed in Note 16. 

The Company uses the current expected credit loss model in valuing accounts receivable and loan 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 Statements 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 that is held in the parent entity as a hedge of its net investment in operations for which the U.S. dollar is the functional currency. As a non-derivative financial instrument, it 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 the fair value of the net investment in the U.S. subsidiary. If effective, the unrealized foreign exchange gains and losses arising from the translation of the U.S. denominated debt are recorded in Other Comprehensive Income/(Loss) (“OCI”), net of tax, to the extent the net investment in the U.S. subsidiary supports the U.S. denominated debt.

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).

In connection with the sale of certain Canadian assets during the year, the Company provided a loan to the purchaser. The loan receivable is recorded at its amortized cost basis on the Consolidated Balance Sheets.

Marketable securities are classified as held for trading and carried at fair value based on a level 1 designation, with changes in fair value recorded in Transaction costs and other expense/(income). When the instruments are ultimately sold any gains or losses are recognized in Transaction costs and other expense/(income).

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, 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/(loss). 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.

Foreign Currency

m) Foreign Currency

i. Foreign currency transactions

Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars in Canada and U.S. dollars in the U.S.) 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/(loss) in the period in which they arise.

ii. Foreign currency translation

For financial statement presentation, assets and liabilities of Enerplus’ Canadian operations, which have a Canadian dollar functional currency, are translated into U.S. 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.

Share-Based Compensation

n) 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.

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 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.  

Net Income/(Loss) Per Share

o) 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 outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price.

Contingencies

p) 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.

Government Assistance

q) Government Assistance

In 2020, the Alberta, Saskatchewan, and British Columbia provincial governments created programs and provided funding to support the clean-up of inactive or abandoned crude oil and natural gas wells. Enerplus applied for and benefited from these programs in 2022 and 2021. The programs provide funding directly to oil field service contractors engaged by companies to perform abandonment, remediation, and reclamation work. As work is completed, the contractors submit invoices to the provincial government for reimbursement for the pre-approved funding amounts. Enerplus recognizes the assistance as the abandonment, remediation, and reclamation work is completed by the contractor. The benefit of the funding received by the contractor is reflected as a reduction of asset retirement obligation and recorded as part of Transaction costs and other expense/(income) in the Consolidated Statements of Income/(Loss).

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ACCOUNTS RECEIVABLE (Tables)

12 Months Ended

Dec. 31, 2022

ACCOUNTS RECEIVABLE

Schedule of accounts receivable

($ thousands)	December 31, 2022		December 31, 2021
Accrued revenue	$	244,494	$	208,160
Accounts receivable – trade		35,019		23,697
Allowance for doubtful accounts		(2,923)		(3,869)
Total accounts receivable, net of allowance for doubtful accounts	$	276,590	$	227,988

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") (Tables)

12 Months Ended

Dec. 31, 2022

PROPERTY, PLANT AND EQUIPMENT ("PP&E")

Schedule of property, plant and equipment

			Accumulated Depletion,
At December 31, 2022			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties(1)	$	13,023,018	$	(11,700,114)	$	1,322,904
Crude oil and natural gas properties – Canadian divestments(2)		(5,808,025)		5,808,025		—
Other capital assets		99,283		(88,598)		10,685
Total PP&E	$	7,314,276	$	(5,980,687)	$	1,333,589

			Accumulated Depletion,
At December 31, 2021			Depreciation,
($ thousands)	Cost		and Impairment		Net Book Value
Crude oil and natural gas properties(1)	$	13,075,987	$	(11,822,482)	$	1,253,505
Other capital assets		103,355		(89,468)		13,887
Total PP&E	$	13,179,342	$	(11,911,950)	$	1,267,392

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

(2) The Company removed the Canadian cost centre’s historical PP&E balances upon the divestment of the Canadian assets.

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IMPAIRMENT (Tables)

12 Months Ended

Dec. 31, 2022

IMPAIRMENT

Schedule of property, plant and equipment impairment expense

($ thousands)	2022		2021		2020
Crude oil and natural gas properties:
U.S. cost centre	$	—	$	—	$	650,780
Canada cost centre		—		3,420		100,943
Total impairment expense	$	—	$	3,420	$	751,723

Schedule of 12-month average trailing benchmark prices and exchange rates used in the ceiling tests

	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub Gas		Exchange Rate
Period	$/bbl		CDN$/bbl		$/Mcf		CDN$/US$
2022	$	94.14	$	119.13	$	6.25		0.77
2021		66.55		78.15		3.64		0.80
2020		39.54		45.56		2.00		0.75

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ACCOUNTS PAYABLE (Tables)

12 Months Ended

Dec. 31, 2022

ACCOUNTS PAYABLE

Schedule of accounts payable

($ thousands)	December 31, 2022		December 31, 2021
Accrued payables	$	110,267	$	106,222
Accounts payable – trade		288,215		260,786
Total accounts payable	$	398,482	$	367,008

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DEBT (Tables)

12 Months Ended

Dec. 31, 2022

DEBT

Schedule of debt

($ thousands)	December 31, 2022		December 31, 2021
Current:
Senior notes	$	80,600	$	100,600
Long-term:
Bank credit facilities		56,316		397,971
Senior notes		122,600		203,200
Total debt	$	259,516	$	701,771

				Original	Remaining
			Coupon	Principal	Principal
Issue Date	Interest Payment Dates	Principal Repayment	Rate	($ thousands)	($ thousands)
September 3, 2014	March 3 and Sept 3	4 equal annual installments beginning September 3, 2023	3.79%	$200,000	$84,000
May 15, 2012	May 15 and Nov 15	2 equal annual installments beginning May 15, 2023	4.40%	$355,000	$119,200
		Total carrying value at December 31, 2022			$ 203,200

($ thousands)	December 31, 2022		December 31, 2021
Current portion of long-term debt	$	80,600	$	100,600
Long-term debt		178,916		601,171
Total debt	$	259,516	$	701,771
Less: Cash and cash equivalents		(38,000)		(61,348)
Net debt	$	221,516	$	640,423

b) Adjusted funds flow

($ thousands)		2022		2021		2020
Cash flow from/(used in) operating activities	$	1,173,382	$	604,839	$	335,884
Asset retirement obligation settlements		17,401		12,951		13,275
Changes in non-cash operating working capital		39,506		94,643		(83,669)
Adjusted funds flow	$	1,230,289	$	712,433	$	265,490

c) Net debt to adjusted funds flow ratio

($thousands)	December 31, 2022		December 31, 2021
Net debt	$	221,516	$	640,423
Trailing adjusted funds flow		1,230,289		712,433
Net debt to adjusted funds flow ratio	$	0.2x	$	0.9x

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ASSET RETIREMENT OBLIGATION ("ARO") (Tables)

12 Months Ended

Dec. 31, 2022

ASSET RETIREMENT OBLIGATION ("ARO")

Schedule of changes in asset retirement obligation

($ thousands)	December 31, 2022		December 31, 2021
Balance, beginning of year	$	132,814	$	102,325
Change in estimates		48,419		26,586
Property acquisition and development activity		3,985		1,304
Bruin acquisition (Note 3)		—		21,964
Dunn County acquisition (Note 3)		—		5,880
Divestments (Note 3)		(58,284)		(13,525)
Settlements		(17,401)		(12,951)
Government assistance		(1,744)		(4,594)
Accretion expense		6,873		5,825
Balance, end of year	$	114,662	$	132,814

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LEASES (Tables)

12 Months Ended

Dec. 31, 2022

LEASES

Summary of leases

($ thousands)	December 31, 2022		December 31, 2021
Assets
Operating right-of-use assets	$	20,556	$	26,118
Liabilities
Current operating lease liabilities	$	13,664	$	10,618
Non-current operating lease liabilities		9,262		18,265
Total lease liabilities	$	22,926	$	28,883
Weighted average remaining lease term (years)
Operating leases		2.4		3.3
Weighted average discount rate
Operating leases		3.7%		3.4%

($ thousands)	2022		2021
Operating lease cost	$	12,409	$	11,378
Variable lease cost		3,847		633
Short-term lease cost		7,163		3,469
Sublease income		(1,091)		(1,083)
Total	$	22,328	$	14,397

($ thousands)	2022			2021
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases	$	10,552	$	11,571
Right-of-use assets obtained/(terminated) in exchange for lease liabilities:
Operating leases	$	5,651	$	10,030

Summary of maturity of leases

($ thousands)	Operating Leases
2023	$	14,278
2024		6,475
2025		1,099
2026		966
2027		988
After 2027		165
Total lease payments	$	23,971
Less imputed interest		(1,045)
Total discounted lease payments	$	22,926
Current portion of lease liabilities	$	13,664
Non-current portion of lease liabilities	$	9,262

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CRUDE OIL AND NATURAL GAS SALES (Tables)

12 Months Ended

Dec. 31, 2022

CRUDE OIL AND NATURAL GAS SALES

Tabular disclosure of revenue from oil and natural gas sales during the period

2022						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	2,205,876	$	1,646,453	$	455,678	$	103,731	$	14
Canada		147,498		131,283		10,918		4,760		537
Total	$	2,353,374	$	1,777,736	$	466,596	$	108,491	$	551

2021						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	1,355,255	$	1,055,748	$	219,552	$	79,930	$	25
Canada		127,320		111,070		11,127		4,348		775
Total	$	1,482,575	$	1,166,818	$	230,679	$	84,278	$	800

2020						Natural		Natural gas
($ thousands)		Total revenue		Crude oil(1)		gas(1)		liquids(1)		Other(2)
United States	$	480,822	$	380,074	$	92,453	$	8,182	$	113
Canada		72,917		59,642		9,239		2,591		1,445
Total	$	553,739	$	439,716	$	101,692	$	10,773	$	1,558

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

(2) Includes third party processing income.

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GENERAL AND ADMINISTRATIVE EXPENSE (Tables)

12 Months Ended

Dec. 31, 2022

GENERAL AND ADMINISTRATIVE EXPENSE

Schedule of General and Administrative Expense

($ thousands)	2022		2021		2020
General and administrative expense excluding share-based compensation(1)	$	42,374	$	38,013	$	33,347
Share-based compensation expense		27,580		18,794		9,750
General and administrative expense	$	69,954	$	56,807	$	43,097

(1) Includes non-cash lease credit of $395 in 2022, $365 in 2021, $212 in 2020.

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FOREIGN EXCHANGE (Tables)

12 Months Ended

Dec. 31, 2022

FOREIGN EXCHANGE

Schedule of foreign exchange (gain)/loss

($ thousands)	2022		2021		2020
Realized:
Foreign exchange (gain)/loss	$	(121)	$	3,477	$	771
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company		(937)		(2,330)		(902)
Unrealized:
Foreign exchange (gain)/loss on U.S. dollar working capital in parent company		11,217		(8,055)		1,363
Foreign exchange (gain)/loss	$	10,159	$	(6,908)	$	1,232

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2022

INCOME TAXES

Schedule of the Company's provision for income taxes

($ thousands)	2022		2021		2020
Current tax
United States	$	28,063	$	2,700	$	(10,716)
Canada		—		(11)		—
Current tax expense/(recovery)		28,063		2,689		(10,716)
Deferred tax
United States	$	217,943	$	148,920	$	(167,835)
Canada		47,290		(50,165)		(20,425)
Deferred tax expense/(recovery)		265,233		98,755		(188,260)
Income tax expense/(recovery)	$	293,296	$	101,444	$	(198,976)

Schedule of reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes

($ thousands)	2022		2021		2020
Income/(loss) before taxes
United States	$	966,646	$	544,464	$	(877,406)
Canada		240,952		(208,579)		(14,921)
Total income/(loss) before taxes		1,207,598		335,885		(892,327)
Canadian statutory rate		23%		24%		24%
Expected income tax expense/(recovery)	$	277,748	$	80,612		(214,158)
Impact on taxes resulting from:
Foreign and statutory rate differences	$	35,636	$	19,297	$	(27,918)
Investment tax credit		(14,245)		—		(9,639)
Non-taxable capital (gains)/losses		(184)		(105)		14,341
Change in valuation allowance		291		(560)		(25,918)
Goodwill impairment, share-based compensation and other		(5,950)		2,200		64,317
Income tax expense/(recovery)	$	293,296	$	101,444	$	(198,976)

Schedule of deferred income tax asset (liability)

At December 31 ($ thousands)	2022		2021
Canadian deferred income tax asset/(liability)
Property, plant and equipment	$	40,207	$	125,311
Tax loss carry-forwards and other credits		101,909		40,891
Capital loss carryforwards and other capital items		101,078		107,681
Asset retirement obligation		11,368		17,368
Derivative financial instruments		(6,578)		28,907
Other		6,442		10,966
Valuation allowance		(99,428)		(112,847)
Canadian deferred income tax asset/(liability)		154,998		218,276
United States deferred income tax asset/(liability)
Property, plant and equipment	$	(77,868)	$	(45,824)
Tax loss carry-forwards and other credits		1,785		200,057
Asset retirement obligation		15,645		15,528
Other		5,077		(7,180)
United States deferred income tax asset/(liability)		(55,361)		162,582
Total deferred income tax asset/(liability)	$	99,637	$	380,858

Summary of loss carry-forwards available for tax reporting purposes

At December 31 ($ thousands)	2022		Expiration Date
Canada Federal
Non-capital losses	$	365,000	2031-2042

Schedule of changes in the balance of Enerplus' unrecognized tax benefits

($ thousands)	2022		2021		2020
Balance, beginning of year	$	15,485	$	15,485	$	—
Increase – tax positions in prior periods		—		—		15,485
Balance, end of year	$	15,485	$	15,485	$	15,485

Summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities

Jurisdiction	Taxation Years
United States – Federal	2019-2022
Canada – Federal	2018-2022

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SHAREHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2022

SHAREHOLDERS' EQUITY

Schedule of share capital

	2022			2021			2020
(thousands)	Shares	Amount		Shares	Amount		Shares	Amount
Balance, beginning of year	243,852	$	3,094,061	222,548	$	3,113,829	221,744	$	3,106,875
Issued/(Purchased) for cash:
Purchase of common shares under Normal Course Issuer Bid	(27,925)		(266,694)	(12,898)		(128,686)	(340)		(3,582)
Issue of shares (net of tax effected issue costs)	—		—	33,062		99,516	—		—
Non-cash:
Share-based compensation – treasury settled(1)	1,358		9,962	1,140		9,402	1,160		10,694
Cancellation of predecessor shares	—		—	—		—	(16)		(158)
Balance, end of year	217,285	$	2,837,329	243,852	$	3,094,061	222,548	$	3,113,829

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

Summary of share-based compensation expense which is included in General and Administrative expense on the Consolidated Income Statements

($ thousands)	2022		2021		2020
Cash:
Long-term incentive plans (recovery)/expense	$	5,664	$	6,875	$	(934)
Non-Cash:
Long-term incentive plans expense		22,924		13,789		9,720
Equity swap (gain)/loss		(1,008)		(1,870)		964
Share-based compensation expense	$	27,580	$	18,794	$	9,750

Schedule of PSU, RSU and DSU activity

For the year ended December 31, 2022	Cash-settled LTI Plans	Equity-settled LTI Plans		Total
(thousands of units)	DSU/DRSU	PSU(1)	RSU
Balance, beginning of year	589	3,981	3,065	7,635
Granted	89	809	837	1,735
Vested	(45)	(1,030)	(1,316)	(2,391)
Forfeited	—	(71)	(265)	(336)
Balance, end of year	633	3,689	2,321	6,643

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

Schedule of cumulative share-based compensation expense recognized to-date

At December 31, 2022 ($ thousands, except for years)	PSU(1)		RSU		Total
Cumulative recognized share-based compensation expense	$	21,616	$	10,368	$	31,984
Unrecognized share-based compensation expense		11,815		4,136		15,951
Fair value	$	33,431	$	14,504	$	47,935
Weighted-average remaining contractual term (years)		1.2		0.9

(1) Includes estimated performance multipliers.

Schedule of net income/(loss) per share

(thousands, except per share amounts)	2022		2021		2020
Net income/(loss)	$	914,302	$	234,441	$	(693,351)
Weighted average shares outstanding – Basic		233,946		251,909		222,503
Dilutive impact of share-based compensation(1)		8,727		7,942		—
Weighted average shares outstanding – Diluted		242,673		259,851		222,503
Net income/(loss) per share
Basic	$	3.91	$	0.93	$	(3.12)
Diluted	$	3.77	$	0.90	$	(3.12)

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

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2022

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Schedule of change in fair value of derivative financial instruments

							Income
Gain/(Loss) ($ thousands)	2022		2021		2020		Statement Presentation
Equity Swaps	$	1,008	$	1,870	$	(964)	G&A expense
Commodity Contracts:
Crude oil		125,842		(111,655)		(19,891)	Commodity derivative
Natural gas		23,676		249		2,781	instruments
Total Unrealized Gain/(Loss)	$	150,526	$	(109,536)	$	(18,074)

Summary of the income statement effects of Enerplus' commodity derivative instruments

($ thousands)	2022		2021		2020
Unrealized change in fair value gain/(loss)	$	149,518	$	(111,406)	$	(17,110)
Net realized cash gain/(loss)		(347,204)		(163,026)		92,852
Commodity contracts gain/(loss)	$	(197,686)	$	(274,432)	$	75,742

Summary of the fair value of derivative financial instruments

	December 31, 2022				December 31, 2021
	Assets		Liabilities			Assets		Liabilities
($ thousands)	Current		Current			Current		Current		Long-term
Equity Swaps	$	—	$	—		$	—	$	969	$	—
Commodity Contracts:
Crude oil		9,834		10,421			1,771		141,364		7,098
Natural gas		26,708		—			3,897		867		—
Total	$	36,542	$	10,421		$	5,668	$	143,200	$	7,098

Summary of management positions

Crude Oil Instruments:

Instrument Type(1)(2)
	Jan 1, 2023 - Jun 30, 2023		Jul 1, 2023 - Oct 31, 2023		Nov 1, 2023 - Dec 31, 2023
	bbls/day	$/bbl	bbls/day	$/bbl	bbls/day	$/bbl
WTI Purchased Put	15,000	79.33	5,000	85.00	5,000	85.00
WTI Sold Put	15,000	61.67	5,000	65.00	5,000	65.00
WTI Sold Call	15,000	114.31	5,000	128.16	5,000	128.16
Brent – WTI Spread	10,000	5.47	10,000	5.47	10,000	5.47
WTI Purchased Swap	250	64.85	250	64.85	—	—
WTI Sold Swap(3)	250	42.10	250	42.10	—	—
WTI Purchased Put(3)	2,000	5.00	2,000	5.00	2,000	5.00
WTI Sold Call(3)	2,000	75.00	2,000	75.00	2,000	75.00

(1) The total average deferred premium spent on the Company’s outstanding crude oil contracts is $1.25/bbl from January 1, 2023 – December 31, 2023.

(2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes.

(3) Outstanding commodity derivative instruments acquired as part of the Bruin Acquisition.

Natural Gas Instruments:

Instrument Type(1)	Jan 1, 2023 – Jan 31, 2023		Feb 1, 2023 – Feb 28, 2023		Mar 1, 2023 – Mar 31, 2023
	MMcf/day	$/Mcf	MMcf/day	$/Mcf	MMcf/day	$/Mcf
NYMEX Purchased Swap	—	—	120.0	3.10	120.0	2.44
NYMEX Purchased Put	120.0	6.27	120.0	6.27	120.0	6.27
NYMEX Sold Call	120.0	18.17	120.0	18.17	120.0	18.17
TZ6 NNY Basis Swap	—	—	—	—	12.5	0.41

(1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

Instrument Type(1)	Apr 1, 2023 – Oct 31, 2023
	MMcf/day	$/Mcf
NYMEX Purchased Put	50.0	4.05
NYMEX Sold Call	50.0	7.00

(1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf.

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2022

COMMITMENTS AND CONTINGENCIES

Schedule of minimum annual commitments

			Minimum Annual Commitment Each Year
($ thousands)		Total	2023		2024		2025		2026		2027		Thereafter
Senior notes(1)	$	203,200	$	80,600	$	80,600	$	21,000	$	21,000	$	—	$	—
Transportation commitments		487,604		71,329		72,598		73,428		73,975		61,852		134,422
Service workover rigs commitments		7,884		7,884		—		—		—		—		—
Purchase commitments		2,100		2,100		—		—		—		—		—
Total commitments(2)	$	700,788	$	161,913	$	153,198	$	94,428	$	94,975	$	61,852	$	134,422

(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.

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GEOGRAPHICAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2022

GEOGRAPHICAL INFORMATION

Schedule of geographical information

As at and for the year ended December 31, 2022 ($ thousands)	U.S.		Canada		Total
Crude oil and natural gas sales	$	2,205,876	$	147,498	$	2,353,374
Depletion, depreciation and accretion		286,438		22,929		309,367
Property, plant and equipment		1,329,545		4,044		1,333,589
Deferred income tax asset		—		154,998		154,998
Deferred income tax liability		55,361		—		55,361

As at and for the year ended December 31, 2021 ($ thousands)		U.S.		Canada		Total
Crude oil and natural gas sales	$	1,355,255	$	127,320	$	1,482,575
Depletion, depreciation and accretion		246,949		24,387		271,336
Property, plant and equipment		1,179,070		88,322		1,267,392
Deferred income tax asset		162,582		218,276		380,858

As at and for the year ended December 31, 2020 ($ thousands)		U.S.		Canada		Total
Crude oil and natural gas sales	$	480,822	$	72,917	$	553,739
Depletion, depreciation and accretion		183,226		34,892		218,118
Property, plant and equipment		375,634		88,167		463,801
Deferred income tax asset		311,502		165,512		477,014

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2022

SUPPLEMENTAL CASH FLOW INFORMATION

Schedule of net change in non-cash operating working capital

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Accounts receivable	$	(45,837)	$	(144,413)	$	84,685
Other assets		(2,442)		(7,583)		(3,333)
Accounts payable – operating		8,773		57,353		2,317
Non-cash operating activities	$	(39,506)	$	(94,643)	$	83,669

Schedule of supplementary cash flow information

b) Changes in Non-Cash Financing Working Capital

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Dividends payable	$	—	$	(1,749)	$	65
Non-cash financing activities	$	—	$	(1,749)	$	65

c) Changes in Non-Cash Investing Working Capital  

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Accounts payable – investing(1)	$	3,420	$	32,793	$	(28,390)

(1) 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.

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Settlement on divestment'(1)	$	(13,053)	$	—	$	—

(1) Relates to funding abandonment and reclamation obligation requirements on previously disposed assets. Refer to Note 9.

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Loan receivable	$	(31,172)	$	—	$	—
Marketable securities		(20,654)		—		—
Accounts receivable		(3,128)		—		—
Non-cash working capital – Canadian divestments(1)	$	(54,954)	$	—	$	—

(1) Refer to Note 3.

d) Cash Income taxes and Interest payments

($ thousands)	December 31, 2022		December 31, 2021		December 31, 2020
Income taxes paid/(received)	$	26,061	$	5,500	$	(42,716)
Interest paid	$	24,399	$	25,808	$	21,276

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SIGNIFICANT ACCOUNTING POLICIES - Transportation (Details)	12 Months Ended
	Dec. 31, 2022 agreement
Transportation
Number of agreement types common in the industry	2

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SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details)	Dec. 31, 2022
Oil and Natural Gas Properties
Discount rate applied to estimated future net cash flows from proved oil and gas reserves (as a percent)	10.00%

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SIGNIFICANT ACCOUNTING POLICIES - Financial Instruments (Details)	12 Months Ended
	Dec. 31, 2022 category
Financial Instruments
Number of categories in which financial instruments are classified	5

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SIGNIFICANT ACCOUNTING POLICIES - Share-Based Compensation (Details)	12 Months Ended
	Dec. 31, 2022
Share-Based Compensation
Authorized percentage to issue outstanding common shares from treasury (as a percent)	4.50%
RSU
Share-Based Compensation
Award vesting percentage (as a percent)	33.33%
Award vesting period	3 years
PSU
Share-Based Compensation
Award vesting period	3 years
Multiplier, low end of range	0
Multiplier, high end of range	2

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ACQUISITIONS & DIVESTMENTS - Divestments (Details) $ in Thousands, shares in Millions, $ in Millions			2 Months Ended	12 Months Ended
	Dec. 19, 2022 USD ($) shares	Oct. 31, 2022 USD ($) shares	Feb. 23, 2023 USD ($)	Dec. 31, 2022 USD ($) $ / bbl	Dec. 31, 2021 USD ($)	Dec. 19, 2022 CAD ($) shares	Oct. 31, 2022 CAD ($) shares	Nov. 02, 2021 USD ($)
Divestments
Gain on divestment of assets				$ 151,937
Reduction in asset retirement obligation				58,284	$ 13,525
Current portion of outstanding loan receivable				17,700
Long-term portion of outstanding loan receivable				13,400
Marketable securities				23,100
Marketable securities, unrealized gain (loss)				2,400
Canadian Assets, Located in Alberta | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Divestments
Total consideration subject to customary purchase price adjustments		$ 104,400					$ 142.2
Total consideration subject to customary purchase price adjustments, cash		$ 59,300
Total consideration subject to customary purchase price adjustments, common shares (in shares) | shares		3.0					3.0
Total consideration subject to customary purchase price adjustments, common shares		$ 12,100
Total consideration subject to customary purchase price adjustments, secured loan		$ 33,000
Total consideration subject to customary purchase price adjustments, secured loan, interest rate (as a percent)		10.00%					10.00%
Divestment, consideration		$ 80,800
Gain on divestment of assets		64,500
Reduction in asset retirement obligation		$ 31,600
Canadian Assets, Substantially All Remaining Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Divestments
Total consideration subject to customary purchase price adjustments	$ 174,500					$ 238.2
Total consideration subject to customary purchase price adjustments, cash	$ 153,900
Total consideration subject to customary purchase price adjustments, common shares (in shares) | shares	3.8					3.8
Total consideration subject to customary purchase price adjustments, common shares	$ 20,700
Divestment, consideration	132,200
Gain on divestment of assets	87,400
Reduction in asset retirement obligation	$ 26,500
Sleeping Giant Field in Montana and Russian Creek Area in North Dakota | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Divestments
Total consideration subject to customary purchase price adjustments								$ 115,000
Divestment, consideration								$ 107,800
Contingent consideration				$ 2,500
WTI Oil Price average minimum in 2023 (in dollars per barrel) | $ / bbl				60
Sleeping Giant Field in Montana and Russian Creek Area in North Dakota | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Subsequent Event
Divestments
Contingent consideration received			$ 2,500

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ACQUISITIONS & DIVESTMENTS - Business Combination (Details) - Bruin E&P HoldCo, LLC $ in Millions	Mar. 10, 2021 USD ($)
Acquisition, date of acquisition
Effective date	Mar. 10, 2021
Acquisition, additional information
Equity interest acquired (as a percent)	100.00%
Acquisition, cash consideration
Total cash consideration subject to certain purchase price adjustments	$ 465.0
Consideration	$ 420.2

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ACQUISITIONS & DIVESTMENTS - Asset Acquisition (Details) - Assets in Dunn County, North Dakota $ in Millions	Apr. 30, 2021 USD ($)
Asset acquisition
Effective date	Apr. 30, 2021
Total cash consideration subject to customary purchase price adjustments	$ 312.0
Asset acquisition, consideration transferred	$ 306.8

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ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable
Accrued revenue	$ 244,494	$ 208,160
Accounts receivable - trade	35,019	23,697
Allowance for doubtful accounts	(2,923)	(3,869)
Total accounts receivable, net of allowance for doubtful accounts	$ 276,590	$ 227,988

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Tabular Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Crude oil and natural gas properties
Crude oil and natural gas properties, cost	$ 13,023,018	$ 13,075,987
Crude oil and natural gas properties, accumulated depreciation, and impairment	(11,700,114)	(11,822,482)
Crude oil and natural gas properties, net book value	1,322,904	1,253,505
Crude oil and natural gas properties, cost - Canadian divestment	(5,808,025)
Crude oil and natural gas properties, accumulated depreciation, and impairment - Canadian divestment	5,808,025
Crude oil and natural gas properties, net book value - Canadian divestment	0
Other capital assets
Other capital assets, cost	99,283	103,355
Other capital assets, accumulated depletion, depreciation, and impairment	(88,598)	(89,468)
Other capital assets, net book value	10,685	13,887
Property, plant and equipment
Total PP&E, cost	7,314,276	13,179,342
Total PP&E, accumulated depletion, depreciation, and impairment	(5,980,687)	(11,911,950)
Property, plant and equipment	$ 1,333,589	$ 1,267,392	$ 463,801

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Acquisitions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Oil and Gas Properties and Land
Property, plant and equipment
Property, plant and equipment, additions	$ 22.5	$ 857.1

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Divestments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property divestments
Property divestments	$ 231,400	$ 112,700
Gain on divestment of assets
Gain on divestment of assets	$ 151,937

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IMPAIRMENT - PP&E - Tabular Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment
Impairment expense	$ 0	$ 3,420	$ 751,723
U.S.
Impairment
Impairment expense			650,780
Canada
Impairment
Impairment expense		$ 3,420	$ 100,943

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IMPAIRMENT - PP&E - General Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment
Asset impairment	$ 0	$ 3,420	$ 751,723

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IMPAIRMENT - PP&E - Ceiling Test (Details)	Dec. 31, 2022 $ / Mcf $ / bbl $ / $	Dec. 31, 2021 $ / bbl $ / Mcf $ / $	Dec. 31, 2020 $ / bbl $ / Mcf $ / $
Impairment
WTI Crude Oil US$/bbl (in dollars per barrel)	94.14	66.55	39.54
Edm Light Crude CDN$/bbl (in Canadian dollar per barrel)	119.13	78.15	45.56
U.S. Henry Hub Gas US$/Mcf (in dollars per Mcf) | $ / Mcf	6.25	3.64	2.00
Exchange Rate US$/CDN$ (in Canadian dollars per US dollars) | $ / $	0.77	0.80	0.75

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IMPAIRMENT - Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Impairment
Goodwill		$ 0	$ 0
Goodwill impairment	$ 149,217

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ACCOUNTS PAYABLE (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounts Payable
Accrued payables	$ 110,267	$ 106,222
Accounts payable - trade	288,215	260,786
Total accounts payable	$ 398,482	$ 367,008

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DEBT - Total Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt
Long-term debt, current portion	$ 80,600	$ 100,600
Long-term debt, non-current portion	178,916	601,171
Total debt	259,516	701,771
Senior Notes
Debt
Long-term debt, current portion	80,600	100,600
Long-term debt, non-current portion	122,600	203,200
Total debt	203,200	303,800
Unsecured Debt
Debt
Long-term debt, non-current portion	56,316	397,971
Total debt	$ 56,300	$ 400,000

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DEBT - Bank Credit Facilities (Details) - Unsecured Debt - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2022	Dec. 31, 2021	Dec. 31, 2022	Feb. 28, 2022
Three-year Senior Unsecured Term Loan
Debt
Principal amount of debt		$ 400.0
Debt instrument, maturity date		Mar. 10, 2024
Revolving Bank Credit Facility
Debt
Line of credit facility, maximum borrowing capacity				$ 400.0
Sustainability-linked Lending Bank Credit Facilities
Debt
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduce or increase borrowing costs (as a percent)			0.05%
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduction in Scope 1 and Scope 2 greenhouse gas emissions intensity by 2030 (as a percent)			35.00%
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduction in freshwater usage in well completions by 2025 (as a percent)			50.00%
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduction in Lost Time Injury Frequency based on three-year trailing average (as a percent)			25.00%
Sustainability-linked Lending Bank Credit Facility
Debt
Line of credit facility, maximum borrowing capacity	$ 365.0
Debt instrument, term	3 years
Line of credit facility, expiration date	Oct. 31, 2025
Debt issuance costs, net			$ 1.5
Senior Unsecured, Covenant-based, Sustainability-linked Lending Bank Credit Facility
Debt
Line of credit facility, maximum borrowing capacity	$ 900.0
Debt instrument, term	4 years
Debt issuance costs, net			$ 1.7
Senior Unsecured, Covenant-based, Sustainability-linked Lending Bank Credit Facility, Maturing 31 October 2025
Debt
Line of credit facility, maximum borrowing capacity	$ 50.0
Line of credit facility, expiration date	Oct. 31, 2025
Senior Unsecured, Covenant-based, Sustainability-linked Lending Bank Credit Facility, Maturing 31 October 2026
Debt
Line of credit facility, maximum borrowing capacity	$ 850.0
Line of credit facility, expiration date	Oct. 31, 2026

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DEBT - Amortization of Debt Issuance Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt
Amortization of debt issuance costs	$ 1,476	$ 1,093

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DEBT - Senior Notes - General Information (Details) - Senior Notes $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Senior Notes, 3.79 Percent, Issued September 3, 2014
Debt
Principal repayment amount	$ 21.0
Senior Notes, 4.40 Percent, Issued May 15, 2012, Annual Installments
Debt
Principal repayment amount	59.6
Senior Notes, 4.40 Percent, Issued May 15, 2012, Bullet Payment
Debt
Principal repayment amount	$ 20.0

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DEBT - Senior Notes - Tabular Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt
Remaining principal / carrying value	$ 259,516	$ 701,771
Senior Notes
Debt
Remaining principal / carrying value	$ 203,200	$ 303,800
Senior Notes | Senior Notes, 3.79 Percent, Issued September 3, 2014
Debt
Coupon rate (as a percent)	3.79%
Original principal	$ 200,000
Remaining principal / carrying value	$ 84,000
Senior Notes | Senior Notes, 4.40 Percent, Issued May 15, 2012
Debt
Coupon rate (as a percent)	4.40%
Original principal	$ 355,000
Remaining principal / carrying value	$ 119,200

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DEBT - Net Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt
Long-term debt, current portion	$ 80,600	$ 100,600
Long-term debt, non-current portion	178,916	601,171
Long-term debt	259,516	701,771
Less: Cash and cash equivalents	(38,000)	(61,348)
Net debt	$ 221,516	$ 640,423

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DEBT - Adjusted Funds Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Activities
Cash flow from/(used in) operating activities	$ 1,173,382	$ 604,839	$ 335,884
Asset retirement obligation settlements	17,401	12,951	13,275
Changes in non-cash operating working capital	39,506	94,643	(83,669)
Adjusted funds flow	$ 1,230,289	$ 712,433	$ 265,490

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DEBT - Net Debt to Adjusted Funds Flow Ratio (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Debt
Net debt	$ 221,516	$ 640,423
Trailing adjusted funds flow	$ 1,230,289	$ 712,433	$ 265,490
Net debt to adjusted funds flow ratio	0.2	0.9

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ASSET RETIREMENT OBLIGATION ("ARO") - Tabular Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Changes in asset retirement obligation
Balance, beginning of year	$ 132,814	$ 102,325
Change in estimates	48,419	26,586
Property acquisition and development activity	3,985	1,304
Bruin acquisition		21,964
Dunn County acquisition		5,880
Divestments	(58,284)	(13,525)
Settlements	(17,401)	(12,951)
Government assistance	(1,744)	(4,594)
Accretion expense	6,873	5,825
Balance, end of year	$ 114,662	$ 132,814

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ASSET RETIREMENT OBLIGATION ("ARO") - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation
Asset retirement obligation	$ 114,662	$ 132,814
Total undiscounted liability	262,400	132,800	$ 303,300
Government assistance	1,744	$ 4,594
Abandonment and reclamation obligation requirements expense	$ 13,053

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LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases
Operating right-of-use assets	$ 20,556	$ 26,118
Current operating lease liabilities	13,664	10,618
Non-current operating lease liabilities	9,262	18,265
Total lease liabilities	$ 22,926	$ 28,883

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LEASES - Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2022	Dec. 31, 2021
Leases
Weighted average remaining lease term (years), operating leases	2 years 4 months 24 days	3 years 3 months 18 days
Weighted average discount rate, operating leases	3.70%	3.40%

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LEASES - Lease Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease expense
Operating lease cost	$ 12,409	$ 11,378
Variable lease cost	3,847	633
Short-term lease cost	7,163	3,469
Sublease income	(1,091)	(1,083)
Total	$ 22,328	$ 14,397

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LEASES - Maturities of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Maturity of Lease Liabilities
2023	$ 14,278
2024	6,475
2025	1,099
2026	966
2027	988
After 2027	165
Total lease payments	$ 23,971

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LEASES - Gross Difference (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Gross Difference
Total lease payments	$ 23,971
Less: Present value discount	(1,045)
Total discounted lease payments	22,926	$ 28,883
Current portion of lease liabilities	13,664	10,618
Non-current operating lease liabilities	$ 9,262	$ 18,265

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LEASES - Supplemental Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Leases
Cash amounts paid to settle lease liabilities, operating cash flow used for operating leases	$ 10,552	$ 11,571
Right-of-use assets obtained/(terminated) in exchange for lease liabilities, operating leases	$ 5,651	$ 10,030

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CRUDE OIL AND NATURAL GAS SALES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	$ 2,353,374	$ 1,482,575	$ 553,739
Crude Oil
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	1,777,736	1,166,818	439,716
Natural Gas
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	466,596	230,679	101,692
Natural Gas Liquids
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	108,491	84,278	10,773
Other
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	551	800	1,558
U.S.
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	2,205,876	1,355,255	480,822
U.S. | Crude Oil
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	1,646,453	1,055,748	380,074
U.S. | Natural Gas
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	455,678	219,552	92,453
U.S. | Natural Gas Liquids
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	103,731	79,930	8,182
U.S. | Other
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	14	25	113
Canada
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	147,498	127,320	72,917
Canada | Crude Oil
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	131,283	111,070	59,642
Canada | Natural Gas
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	10,918	11,127	9,239
Canada | Natural Gas Liquids
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	4,760	4,348	2,591
Canada | Other
Oil and natural gas revenue by country and by product
Crude oil and natural gas sales	$ 537	$ 775	$ 1,445

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GENERAL AND ADMINISTRATIVE EXPENSE - Tabular Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense excluding share-based compensation	$ 42,374	$ 38,013	$ 33,347
Share-based compensation expense	27,580	18,794	9,750
General and administrative expense	$ 69,954	$ 56,807	$ 43,097

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GENERAL AND ADMINISTRATIVE EXPENSE - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
GENERAL AND ADMINISTRATIVE EXPENSE
Non-cash lease credit	$ 395	$ 365	$ 212

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FOREIGN EXCHANGE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
FOREIGN EXCHANGE
Realized, foreign exchange (gain)/loss	$ (121)	$ 3,477	$ 771
Realized, foreign exchange (gain)/loss on U.S. dollar cash held in parent company	(937)	(2,330)	(902)
Unrealized, foreign exchange (gain)/loss on U.S. dollar working capital in parent company	11,217	(8,055)	1,363
Foreign exchange (gain)/loss	$ 10,159	$ (6,908)	$ 1,232

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INCOME TAXES - Provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current tax expense/(recovery)
United States	$ 28,063	$ 2,700	$ (10,716)
Canada		(11)
Current Tax expense/(recovery)	28,063	2,689	(10,716)
Deferred Tax expense/(recovery)
United States	217,943	148,920	(167,835)
Canada	47,290	(50,165)	(20,425)
Deferred tax expense/(recovery)	265,233	98,755	(188,260)
Income tax expense/(recovery)	$ 293,296	$ 101,444	$ (198,976)

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INCOME TAXES - Income (Loss) Before Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Expenses
United States	$ 966,646	$ 544,464	$ (877,406)
Canada	240,952	(208,579)	(14,921)
Income/(Loss) Before Taxes	$ 1,207,598	$ 335,885	$ (892,327)

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INCOME TAXES - Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes
Canadian statutory rate (as a percent)	23.00%	24.00%	24.00%
Expected income tax expense/(recovery)	$ 277,748	$ 80,612	$ (214,158)
Foreign and statutory rate differences	35,636	19,297	(27,918)
Investment tax credit	(14,245)		(9,639)
Non-taxable capital (gains)/losses	(184)	(105)	14,341
Change in valuation allowance	291	(560)	(25,918)
Goodwill impairment, share-based compensation and other	(5,950)	2,200	64,317
Income tax expense/(recovery)	$ 293,296	$ 101,444	$ (198,976)

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INCOME TAXES - Deferred Tax Assets (Liability) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred income tax asset/(liability)
Valuation allowance	$ (99,428)	$ (112,847)
Total deferred income tax asset	99,637	380,858
Domestic Tax Authority
Deferred income tax asset/(liability)
Derivative financial instruments, net	(6,578)	28,907
Total deferred income tax asset	154,998	218,276
Deferred income tax assets
Property, plant and equipment	40,207	125,311
Tax loss carryforwards and other credits	101,909	40,891
Capital loss carryforwards and other capital items	101,078	107,681
Asset retirement obligation	11,368	17,368
Other	6,442	10,966
Foreign Tax Authority
Deferred income tax asset/(liability)
Other, net	5,077	(7,180)
Total deferred income tax asset		162,582
Total deferred income tax (liability)	(55,361)
Deferred income tax assets
Tax loss carryforwards and other credits	1,785	200,057
Asset retirement obligation	15,645	15,528
Deferred income tax (liabilities)
Property, plant and equipment	$ (77,868)	$ (45,824)

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INCOME TAXES - Operating Loss Carryforwards (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Domestic Tax Authority
Operating Loss Carryforwards
Operating loss carryforward	$ 365,000

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INCOME TAXES - Unrecognized Tax Benefits - Tabular Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in the balance of unrecognized tax benefits
Balance, beginning of year	$ 15,485	$ 15,485	$ 0
Increase - tax positions in prior periods	0	0	15,485
Balance, end of year	$ 15,485	$ 15,485	$ 15,485

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INCOME TAXES - Unrecognized Tax Benefits - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes
Unrecognized tax benefits	$ 15,485	$ 15,485	$ 15,485	$ 0
Unrecognized tax benefits, if recognized, would affect the effective income tax rate	$ 15,485

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INCOME TAXES - Taxation Years by Jurisdiction (Details)	12 Months Ended
	Dec. 31, 2022
Foreign Tax Authority | Earliest Tax Year
Taxation Years
Open tax year	2019
Foreign Tax Authority | Latest Tax Year
Taxation Years
Open tax year	2022
Domestic Tax Authority | Earliest Tax Year
Taxation Years
Open tax year	2018
Domestic Tax Authority | Latest Tax Year
Taxation Years
Open tax year	2022

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SHAREHOLDERS' EQUITY - Share Capital - Tabular Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Increase (decrease) in equity
Balance, beginning of year	$ 609,310	$ 420,965
Balance, beginning of year (in shares)	244,000,000
Issue of shares (net of tax effected issue costs) (in shares)		33,062,500
Purchase of common shares under Normal Course Issuer Bid	$ (410,900)	$ (123,200)	$ (1,900)
Purchase of common shares under Normal Course Issuer Bid (in shares)	(27,924,842)	(12,897,721)	(340,434)
Balance, end of year	$ 1,076,613	$ 609,310	$ 420,965
Balance, end of year (in shares)	217,000,000	244,000,000
Share Capital
Increase (decrease) in equity
Balance, beginning of year	$ 3,094,061	$ 3,113,829	$ 3,106,875
Balance, beginning of year (in shares)	243,852,000	222,548,000	221,744,000
Issue of shares (net of tax effected issue costs)		$ 99,516
Issue of shares (net of tax effected issue costs) (in shares)		33,062,000
Purchase of common shares under Normal Course Issuer Bid	$ (266,694)	$ (128,686)	$ (3,582)
Purchase of common shares under Normal Course Issuer Bid (in shares)	(27,925,000)	(12,898,000)	(340,000)
Share-based compensation - treasury settled	$ 9,962	$ 9,402	$ 10,694
Share-based compensation - treasury settled (in shares)	1,358,000	1,140,000	1,160,000
Cancellation of predecessor shares			$ (158)
Cancellation of predecessor shares (in shares)			(16,000)
Balance, end of year	$ 2,837,329	$ 3,094,061	$ 3,113,829
Balance, end of year (in shares)	217,285,000	243,852,000	222,548,000

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SHAREHOLDERS' EQUITY - Share Capital - Shares Authorized (Details) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Share capital
Share capital, shares authorized, unlimited	Unlimited	Unlimited
Share capital, par value (in dollars per share)	$ 0	$ 0

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SHAREHOLDERS' EQUITY - Share Capital - Dividends (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Dividends
Dividends declared per share (in dollars per share)		$ 0.181	$ 0.121	$ 0.090
Dividends declared		$ 41.6	$ 30.5	$ 20.0
Subsequent Event | Forecast
Dividends
Dividends declared per share (in dollars per share)	$ 0.055

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SHAREHOLDERS' EQUITY - Share Capital - Share Repurchases (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	12 Months Ended
	Feb. 22, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Aug. 16, 2022
Share capital
Normal Course Issuer Bid, purchases during twelve-month period, percentage of public float (as a percent)					10.00%
Shares purchased for cancellation (in shares)		27,924,842	12,897,721	340,434
Average price per share		$ 14.71	$ 9.55	$ 5.63
Purchase of common shares under Normal Course Issuer Bid		$ 410,900	$ 123,200	$ 1,900
Common shares available for repurchase under the current NCIB (in shares)		7,883,479
Subsequent Event
Share capital
Shares purchased for cancellation (in shares)	1,420,927
Average price per share	$ 16.65
Purchase of common shares under Normal Course Issuer Bid	$ 23,700
Share Capital
Share capital
Shares purchased for cancellation (in shares)		27,925,000	12,898,000	340,000
Purchase of common shares under Normal Course Issuer Bid		$ 266,694	$ 128,686	$ 3,582
Accumulated Deficit
Share capital
Purchase of common shares under Normal Course Issuer Bid		$ 144,212	$ (5,504)	$ (1,775)

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SHAREHOLDERS' EQUITY - Share Capital - Shares Issued (Details) - 12 months ended Dec. 31, 2021 $ in Millions	USD ($) shares	$ / shares
Common shares issued
Common shares issued (in shares) | shares	33,062,500
Share price (in CAD per share) | $ / shares		$ 4.00
Gross proceeds	$ 103.4
Net proceeds	99.5
Payment of stock issuance costs	5.1
Tax	$ 1.2

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SHAREHOLDERS' EQUITY - Share-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation
Share-based compensation expense	$ 27,580	$ 18,794	$ 9,750
Cash Settled DSU
Share-based Compensation
Share-based compensation expense	5,664	6,875	(934)
Equity-settled Long-term Incentive Plans
Share-based Compensation
Share-based compensation expense	22,924	13,789	9,720
Equity Swaps
Share-based Compensation
Share-based compensation expense	$ (1,008)	$ (1,870)	$ 964

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SHAREHOLDERS' EQUITY - LTI Plans (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2022 shares
Number of units
Balance, beginning of year (in shares)	7,635
Granted (in shares)	1,735
Vested (in shares)	(2,391)
Forfeited (in shares)	(336)
Balance, end of year (in shares)	6,643
Cash Settled DSU
Number of units
Balance, beginning of year (in shares)	589
Granted (in shares)	89
Vested (in shares)	(45)
Balance, end of year (in shares)	633
PSU
Number of units
Balance, beginning of year (in shares)	3,981
Granted (in shares)	809
Vested (in shares)	(1,030)
Forfeited (in shares)	(71)
Balance, end of year (in shares)	3,689
RSU
Number of units
Balance, beginning of year (in shares)	3,065
Granted (in shares)	837
Vested (in shares)	(1,316)
Forfeited (in shares)	(265)
Balance, end of year (in shares)	2,321

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SHAREHOLDERS' EQUITY - Cash-settled LTI Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation
Accounts payable	$ 398,482	$ 367,008
Cash Settled DSU
Share-based Compensation
Cash share-based compensation (recovery) expense	(5,700)	6,900	$ 900
Accounts payable	$ 11,100	$ 6,300

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SHAREHOLDERS' EQUITY - Equity-settled LTI Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Compensation
Cash withholding taxes	$ 13,386	$ 3,551	$ 5,567
Equity-settled Long-term Incentive Plans
Share-Based Compensation
Cumulative recognized share-based compensation expense	31,984
Unrecognized share-based compensation expense	15,951
Fair value	47,935
PSU
Share-Based Compensation
Cumulative recognized share-based compensation expense	21,616
Unrecognized share-based compensation expense	11,815
Fair value	$ 33,431
Weighted-average remaining contractual term (years)	1 year 2 months 12 days
RSU
Share-Based Compensation
Cumulative recognized share-based compensation expense	$ 10,368
Unrecognized share-based compensation expense	4,136
Fair value	$ 14,504
Weighted-average remaining contractual term (years)	10 months 24 days

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SHAREHOLDERS' EQUITY - Basic and Diluted Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Basic and diluted net income/(loss) per share
Net income/(loss)	$ 914,302	$ 234,441	$ (693,351)
Net income/(loss) - basic	914,302	234,441	(693,351)
Net income/(loss) - diluted	$ 914,302	$ 234,441	$ (693,351)
Weighted average shares outstanding
Weighted average shares outstanding - Basic (in shares)	233,946	251,909	222,503
Dilutive impact of share-based compensation (in shares)	8,727	7,942
Weighted average shares outstanding - Diluted (in shares)	242,673	259,851	222,503
Net income/(loss) per share
Basic (in dollars per share)	$ 3.91	$ 0.93	$ (3.12)
Diluted (in dollars per share)	$ 3.77	$ 0.90	$ (3.12)

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Carrying Value
Receivables
Loans receivable	$ 31.1
Carrying Value | Senior Notes
Debt
Long-term debt	203.2	$ 303.8
Fair Value
Receivables
Loans receivable	31.6
Fair Value | Senior Notes
Debt
Long-term debt	$ 189.5	$ 304.1

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Transfers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)
Fair value, measurement with unobservable inputs reconciliation, recurring basis, asset, transfers, net
Fair value, measurement with unobservable inputs reconciliation, recurring basis, asset, transfers, net	$ 0
Fair value, measurement with unobservable inputs reconciliation, recurring basis, liability, transfers, net
Fair value, measurement with unobservable inputs reconciliation, recurring basis, liability, transfers, net	$ 0

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Change in Fair Value Associated with Equity and Commodity Contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Financial Instruments
Equity Swaps, Gain/(Loss)	$ 150,526	$ (109,536)	$ (18,074)
Total Unrealized Gain/(Loss)	150,526	(109,536)	(18,074)
Equity Swaps
Derivative Financial Instruments
Equity Swaps, Gain/(Loss)	1,008	1,870	(964)
Commodity Contract
Derivative Financial Instruments
Commodity Contracts, Gain/(Loss)	149,518	(111,406)	(17,110)
Commodity Contract | Oil
Derivative Financial Instruments
Commodity Contracts, Gain/(Loss)	125,842	(111,655)	(19,891)
Commodity Contract | Gas
Derivative Financial Instruments
Commodity Contracts, Gain/(Loss)	$ 23,676	$ 249	$ 2,781

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Contracts on the Consolidated Statements of Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Financial Instruments
Commodity contracts gain/(loss)	$ (197,686)	$ (274,432)	$ 75,742
Commodity Contract
Derivative Financial Instruments
Change in fair value gain/(loss)	149,518	(111,406)	(17,110)
Net realized cash gain/(loss)	(347,204)	(163,026)	92,852
Commodity contracts gain/(loss)	$ (197,686)	$ (274,432)	$ 75,742

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value of Derivative Financial Instruments - Tabular Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative asset
Derivative asset, current	$ 36,542	$ 5,668
Derivative liability
Derivative liability, current	10,421	143,200
Derivative liability, noncurrent		7,098
Equity Swaps
Derivative liability
Derivative liability, current		969
Commodity Contract | Oil
Derivative asset
Derivative asset, current	9,834	1,771
Derivative liability
Derivative liability, current	10,421	141,364
Derivative liability, noncurrent		7,098
Commodity Contract | Gas
Derivative asset
Derivative asset, current	$ 26,708	3,897
Derivative liability
Derivative liability, current		$ 867

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value of Derivative Financial Instruments - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Mar. 10, 2021
Derivative Financial Instruments
Derivative assets (liabilities)	$ 26.1	$ (143.7)
Bruin Contract, Counterparties
Derivative Financial Instruments
Derivative assets (liabilities)	(10.1)	(40.2)
Bruin E&P HoldCo, LLC
Derivative Financial Instruments
Derivative liability	$ 2.7	$ 22.8	$ 76.4

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - General Information (Details)	12 Months Ended
	Dec. 31, 2022
Commodity Contract
Risk Management
Maximum percentage of forecasted production volumes net of royalties considered to enter into commodity contracts	80.00%

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - Tabular Disclosure (Details) - Commodity Contract	Feb. 22, 2023 bbl / d MMcf / d $ / Mcf $ / bbl
Crude Oil
Commodity Price Risk
Total average deferred premium on outstanding hedges	1.25
Crude Oil | Put, West Texas Intermediate, 01 January 2023 to 30 June 2023 | Long
Commodity Price Risk
Volume | bbl / d	15,000
Weighted average price	61.67
Crude Oil | Put, West Texas Intermediate, 01 January 2023 to 30 June 2023 | Short
Commodity Price Risk
Volume | bbl / d	15,000
Weighted average price	79.33
Crude Oil | Put, West Texas Intermediate, 01 July 2023 to 31 October 2023 | Long
Commodity Price Risk
Volume | bbl / d	5,000
Weighted average price	65.00
Crude Oil | Put, West Texas Intermediate, 01 July 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | bbl / d	5,000
Weighted average price	85.00
Crude Oil | Put, West Texas Intermediate, 01 November 2023 to 31 December 2023 | Long
Commodity Price Risk
Volume | bbl / d	5,000
Weighted average price	65.00
Crude Oil | Put, West Texas Intermediate, 01 November 2023 to 31 December 2023 | Short
Commodity Price Risk
Volume | bbl / d	5,000
Weighted average price	85.00
Crude Oil | Put, West Texas Intermediate, Bruin, 01 January 2023 to 30 June 2023 | Short
Commodity Price Risk
Volume | bbl / d	2,000
Weighted average price	5.00
Crude Oil | Put, West Texas Intermediate, Bruin, 01 July 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | bbl / d	2,000
Weighted average price	5.00
Crude Oil | Put, West Texas Intermediate, Bruin, 01 November 2023 to 31 December 2023 | Short
Commodity Price Risk
Volume | bbl / d	2,000
Weighted average price	5.00
Crude Oil | Call, West Texas Intermediate, 01 January 2023 to 30 June 2023 | Short
Commodity Price Risk
Volume | bbl / d	15,000
Weighted average price	114.31
Crude Oil | Call, West Texas Intermediate, 01 July 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | bbl / d	5,000
Weighted average price	128.16
Crude Oil | Call, West Texas Intermediate, 01 November 2023 to 31 December 2023 | Short
Commodity Price Risk
Volume | bbl / d	5,000
Weighted average price	128.16
Crude Oil | Call, West Texas Intermediate, Bruin, 01 January 2023 to 30 June 2023 | Short
Commodity Price Risk
Volume | bbl / d	2,000
Weighted average price	75.00
Crude Oil | Call, West Texas Intermediate, Bruin, 01 July 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | bbl / d	2,000
Weighted average price	75.00
Crude Oil | Call, West Texas Intermediate, Bruin, 01 November 2023 to 31 December 2023 | Short
Commodity Price Risk
Volume | bbl / d	2,000
Weighted average price	75.00
Crude Oil | Spread, Brent, West Texas Intermediate, 01 January 2023 to 30 June 2023 | Long
Commodity Price Risk
Volume | bbl / d	10,000
Weighted average price	5.47
Crude Oil | Spread, Brent, West Texas Intermediate, 01 July 2023 to 31 October 2023 | Long
Commodity Price Risk
Volume | bbl / d	10,000
Weighted average price	5.47
Crude Oil | Spread, Brent, West Texas Intermediate, 01 November 2023 to 31 December 2023 | Long
Commodity Price Risk
Volume | bbl / d	10,000
Weighted average price	5.47
Crude Oil | Swap, West Texas Intermediate, 01 January 2023 to 30 June 2023 | Long
Commodity Price Risk
Volume | bbl / d	250
Weighted average price	64.85
Crude Oil | Swap, West Texas Intermediate, 01 July 2023 to 31 October 2023 | Long
Commodity Price Risk
Volume | bbl / d	250
Weighted average price	64.85
Crude Oil | Swap, West Texas Intermediate, Bruin, 01 January 2023 to 30 June 2023 | Short
Commodity Price Risk
Volume | bbl / d	250
Weighted average price	42.10
Crude Oil | Swap, West Texas Intermediate, Bruin, 01 July 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | bbl / d	250
Weighted average price	42.10
Natural Gas | Put, New York Mercantile Exchange, 01 January 2023 to 31 January 2023 | Short
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	6.27
Natural Gas | Put, New York Mercantile Exchange, 01 February 2023 to 28 February 2023 | Short
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	6.27
Natural Gas | Put, New York Mercantile Exchange, 01 March 2023 to 31 March 2023 | Short
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	6.27
Natural Gas | Put, New York Mercantile Exchange, 01 April 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | MMcf / d	50.0
Weighted average price | $ / Mcf	4.05
Natural Gas | Call, New York Mercantile Exchange, 01 January 2023 to 31 January 2023 | Short
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	18.17
Natural Gas | Call, New York Mercantile Exchange, 01 February 2023 to 28 February 2023 | Short
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	18.17
Natural Gas | Call, New York Mercantile Exchange, 01 March 2023 to 31 March 2023 | Short
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	18.17
Natural Gas | Call, New York Mercantile Exchange, 01 April 2023 to 31 October 2023 | Short
Commodity Price Risk
Volume | MMcf / d	50.0
Weighted average price | $ / Mcf	7.00
Natural Gas | Swap, New York Mercantile Exchange, 01 February 2023 to 28 February 2023 | Long
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	3.10
Natural Gas | Swap, New York Mercantile Exchange, 01 March 2023 to 31 March 2023 | Long
Commodity Price Risk
Volume | MMcf / d	120.0
Weighted average price | $ / Mcf	2.44
Natural Gas | Swap, Transco Zone 6 Basis, 01 March 2023 to 31 March 2023 | Long
Commodity Price Risk
Volume | MMcf / d	12.5
Weighted average price | $ / Mcf	0.41

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Foreign Exchange Risk and Net Investment Hedge (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt
Long-term debt	$ 259,516	$ 701,771
Foreign exchange gain/(loss) on net investment hedge, net of tax	(26,541)	4,097	$ 1,780
Senior Notes
Debt
Long-term debt	203,200	303,800
Unsecured Debt
Debt
Long-term debt	$ 56,300	$ 400,000

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Interest Rate Risk (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt
Long-term debt, fixed interest rate, percentage of total debt (as a percent)	78.00%	43.00%
Long-term debt, floating interest rate, percentage of total debt (as a percent)	22.00%	57.00%
Interest rate derivatives
Interest rate derivatives	$ 0	$ 0
Fixed Interest Rate Debt
Debt
Weighted average interest rate (as a percent)	4.20%	4.20%
Floating Interest Rate Debt
Debt
Weighted average interest rate (as a percent)	5.70%	1.90%

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Credit Risk (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Marketing receivables, companies considered investment grade (as a percent)	90.00%	83.00%
Allowance for doubtful accounts	$ 2,923	$ 3,869

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Climate Change Risk (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Asset impairment charges, oil and gas, ceiling test	$ 0

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COMMITMENTS AND CONTINGENCIES - Commitments - Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt
Total debt	$ 259,516	$ 701,771
Senior Notes
Debt
Total debt	203,200	$ 303,800
2023	80,600
2024	80,600
2025	21,000
2026	$ 21,000

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COMMITMENTS AND CONTINGENCIES - Commitments - Other Commitments (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Transportation Commitments
Other Commitments
Total	$ 487,604
2023	71,329
2024	72,598
2025	73,428
2026	73,975
2027	61,852
Thereafter	134,422
Processing Commitments
Other Commitments
Total	7,884
2023	7,884
Service Workover Rigs Commitments
Other Commitments
Total	2,100
2023	$ 2,100

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COMMITMENTS AND CONTINGENCIES - Commitments - Total Commitments (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Total Commitments
Total	$ 700,788
2023	161,913
2024	153,198
2025	94,428
2026	94,975
2027	61,852
Thereafter	$ 134,422

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GEOGRAPHICAL INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Geographical Information
Crude oil and natural gas sales	$ 2,353,374	$ 1,482,575	$ 553,739
Depletion, depreciation and accretion	309,367	271,336	218,118
Property, plant and equipment	1,333,589	1,267,392	463,801
Deferred income tax asset	154,998	380,858	477,014
Deferred income tax liability	55,361
U.S.
Geographical Information
Crude oil and natural gas sales	2,205,876	1,355,255	480,822
Depletion, depreciation and accretion	286,438	246,949	183,226
Property, plant and equipment	1,329,545	1,179,070	375,634
Deferred income tax asset		162,582	311,502
Deferred income tax liability	55,361
Canada
Geographical Information
Crude oil and natural gas sales	147,498	127,320	72,917
Depletion, depreciation and accretion	22,929	24,387	34,892
Property, plant and equipment	4,044	88,322	88,167
Deferred income tax asset	$ 154,998	$ 218,276	$ 165,512

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SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Operating Working Capital (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in Non-Cash Operating Working Capital
Accounts receivable	$ (45,837)	$ (144,413)	$ 84,685
Other assets	(2,442)	(7,583)	(3,333)
Accounts payable - operating	8,773	57,353	2,317
Non-cash operating activities	$ (39,506)	$ (94,643)	$ 83,669

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SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Financing Working Capital (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Changes in Non-Cash Working Capital
Dividends payable	$ (1,749)	$ 65
Non-cash financing activities	$ (1,749)	$ 65

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SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Investing Working Capital (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in Non-Cash Working Capital
Accounts payable - investing	$ 3,420	$ 32,793	$ (28,390)
Settlement on divestment	(13,053)
Loan receivable	(31,172)
Marketable securities	(20,654)
Accounts receivable	(3,128)
Non-cash working capital -Canadian divestments	$ (54,954)

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SUPPLEMENTAL CASH FLOW INFORMATION - Cash Income Taxes and Interest Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Income Taxes and Interest Payments
Income taxes paid/(received)	$ 26,061	$ 5,500	$ (42,716)
Interest paid	$ 24,399	$ 25,808	$ 21,276

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SUPPLEMENTAL CASH FLOW INFORMATION - Other (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
SUPPLEMENTAL CASH FLOW INFORMATION
Distribution associated with a privately held investment	$ 4.6