Exhibit 99.1

ANNUAL INFORMATION FORM

For the year ended December 31, 2023

February 21, 2024

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	14
Overview	14
Summary Of Principal Production Locations	14
Capital Expenditures And Costs Incurred	15
Exploration And Development Activities	15
Oil And Natural Gas Wells And Unproved Properties	15
Description Of Properties	16
Quarterly Production History	17
Quarterly Netback History	18
Tax Horizon	18
Marketing Arrangements And Forward Contracts	19
OIL AND NATURAL GAS RESERVES	20
Summary Of Reserves	20
Forecast Prices And Costs	21
Undiscounted Future Net Revenue By Reserves Category	22
Net Present Value Of Future Net Revenue By Reserves Category And Product Type	22
Estimated Production For Gross Reserves Estimates	22
Future Development Costs	23
Reconciliation Of Reserves	23
Undeveloped Reserves	25
Significant Factors Or Uncertainties	26
Proved And Probable Reserves Not On Production	26
SUPPLEMENTAL OPERATIONAL INFORMATION	27
Environmental, Social And Governance	27
Insurance	29
Personnel	29
DESCRIPTION OF CAPITAL STRUCTURE	30
Common Shares	30
Preferred Shares	30
Senior Unsecured Notes	30
SLL Credit Facilities	30
DIVIDENDS	31
INDUSTRY CONDITIONS	32
Overview	32
Pricing And Marketing Of Crude Oil And Natural Gas	32
Royalties And Incentives	33
Land Tenure	34
Environmental Regulation	34
Climate Change-Related Legislation	36
Worker Safety	37
RISK FACTORS	38
MARKET FOR SECURITIES	57
DIRECTORS AND OFFICERS	58
Directors Of The Corporation	58
Officers Of The Corporation	59

i

Common Share Ownership	59
Conflicts Of Interest	59
Audit & Risk Management Committee Disclosure	60
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	60
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	60
MATERIAL CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF SECURITYHOLDERS	60
INTERESTS OF EXPERTS	60
TRANSFER AGENT AND REGISTRAR	61
ADDITIONAL INFORMATION	61
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 21, 2024, for the year ended December 31, 2023 and all appendices hereto.

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

"Arrangement" means the arrangement, pursuant to Section 193 of the ABCA involving, among others, Enerplus and Chord to be completed pursuant to the Arrangement Agreement. See "General Development of the Business – Developments in the Past Three Years – Recent Developments"

"Arrangement Agreement" means the arrangement agreement dated effective February 21, 2024, between Enerplus and Chord with respect to the Arrangement, as further supplemented, modified, amended or amended and restated in accordance with its terms. See "General Development of the Business – Developments in the Past Three Years – Recent Developments"

"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"

"Chord" means Chord Energy Corporation, a corporation existing under the laws of the State of Delaware

"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" or "Enerplus" 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

"DAPL" means the Dakota Access Pipeline

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

"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, 2023 and 2022 and for each of the years in the three-year period ended December 31, 2023

"GHG" means greenhouse gas

"GLJ" means GLJ Ltd., independent petroleum consultants

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

ENERPLUS 2023 ANNUAL INFORMATION FORM    1

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

"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, 2023 utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2024

"MD&A" means management's discussion and analysis for the year ended December 31, 2023

"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, 2023, utilizing the average of the commodity price forecasts and inflation rates of GLJ, McDaniel and Sproule as of January 1, 2024

"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, 2023, the US$122.6 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, 2023, 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

"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 entered into in connection with the Bruin Acquisition and initially set to mature on March 10, 2024, which was converted into the US$365 million SLL Credit Facility in 2022. See "General Developments of the Business“, “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

"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 2023 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 29, 2023, the exchange rate for one Canadian dollar, expressed in U.S. dollars and based upon the closing rate from Bloomberg, was $0.76. The average exchange rate in 2023 for one Canadian dollar, expressed in U.S. dollars and based upon the average closing rate from Bloomberg, was $0.74.

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

		Multiply
To Convert From	To	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 2023 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, 2023, 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, 2023 and the preparation dates for such information are January 30, 2024 for the McDaniel Reports and February 9, 2024 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 and related realized prices and differentials 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 2023 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.

● NI 51-101 generally requires that at least 75% (based on the attributable estimated future net revenue) of the reserves data that is disclosed in this Annual Information Form has been evaluated or audited by an independent qualified reserves evaluator, whereas the SEC permits disclosure of internally-generated reserves data.

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 2023 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 2023 ANNUAL INFORMATION FORM

Presentation of Financial and Other 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", “free cash flow” and “capital spending”, 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, 2023. 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".

Unless expressly stated, the information contained on, or accessible from, the Corporation's website or any other website or any other report or document the Corporation files with or furnishes to applicable Canadian or U.S. securities regulatory authorities is not incorporated by reference into this Annual Information Form.

The information in this Annual Information Form is presented as of December 31, 2023 and updated to the date of this Annual Information Form, as necessary, and is in regards to the Corporation as a stand-alone entity and without giving effect to the Arrangement.

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 Arrangement, the timing thereof and the effect of the Arrangement on Enerplus and the holders of Common Shares

● 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

ENERPLUS 2023 ANNUAL INFORMATION FORM    7

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

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

● the Corporation's future operating and financial results

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

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

● the Corporation’s ESG strategy, including but not limited to specific targets relating to GHG emissions, as part of Enerplus’ climate risk strategy, and freshwater use reductions

● estimates of the Corporation’s future abandonment and reclamation obligations

● future dividends that may be paid by the Corporation

The forward-looking information contained in this Annual Information Form reflects several material factors and expectations and assumptions made by the Corporation including, without limitation: the completion of the Arrangement on the terms or within the timeline currently contemplated; stability, or no deterioration, in the global economic and market environment, including related to the Ukraine and Russian conflict or the conflict in the Middle East, 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, 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.

The Corporation's current 2024 capital spending budget of $550 million contained in this Annual Information Form assumes: a WTI price of $75 per barrel, a NYMEX natural gas price of $2.50 per Mcf 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:

● the Arrangement may not be completed in a timely manner or at all, due to a failure to satisfy any of the conditions set forth therein or otherwise, or the anticipated benefits of the Arrangement may not be realized

● 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

8    ENERPLUS 2023 ANNUAL INFORMATION FORM

● 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

● 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 Emissions and Scope 2 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.sedarplus.ca, 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.sedarplus.ca, on the Corporation's EDGAR profile at www.sec.gov and on the Corporation's website at www.enerplus.com.

ENERPLUS 2023 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".

The Corporation’s co-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, 2023, 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, 2023 is set forth below.

10    ENERPLUS 2023 ANNUAL INFORMATION FORM

General Development of the Business

DEVELOPMENTS IN THE PAST THREE YEARS

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 an 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 each of January 2023 and 2024, the Corporation received a $2.5 million contingent payment as WTI averaged over $60 per barrel in 2022 and 2023, respectively. 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 new 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, 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".

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.

During 2021, Enerplus repurchased an aggregate of approximately 12.9 million Common Shares for aggregate proceeds of approximately $123.2 million.  

ENERPLUS 2023 ANNUAL INFORMATION FORM    11

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 co-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.                                                                  

During 2022, Enerplus repurchased an aggregate of approximately 27.9 million Common Shares at an aggregate cost of approximately $410.9 million.

Developments in 2023

APPOINTMENT OF NEW DIRECTOR

In May 2023, the Corporation announced the appointment of Ward Polzin to the Board.

SHAREHOLDER RETURNS – DIVIDEND & SHARE REPURCHASES

In August 2023, 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 17, 2023. Enerplus repurchased an aggregate of approximately 16.4 million Common Shares at an aggregate cost of approximately $258.3 million during 2023. From January 1, 2024 to February 20, 2024, the Corporation repurchased an additional approximately 1.1 million Common Shares for an aggregate cost of $16 million.

Recent Developments

Effective February 21, 2024, the Corporation entered into the Arrangement Agreement with Chord, pursuant to which, upon completion of the Arrangement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and US$1.84 in cash for each Common Share.

The Arrangement will be completed as a plan of arrangement under the ABCA and is subject to the approval of at least two-thirds of the votes cast by holders of Enerplus Common Shares at a meeting to be called to consider the Arrangement. The issuance of shares of Chord common stock is subject to the approval of the majority of votes cast by holders of shares of Chord common stock in connection with the transaction, pursuant to the rules of the Nasdaq Global Select Market ("NASDAQ").

The Arrangement has been unanimously approved by the Board and the board of directors of Chord. The Arrangement is subject to customary closing conditions in the United States and Canada, as well as the approvals by Chord and Enerplus’ shareholders referenced above, the approval of the Court of King's Bench of Alberta, the listing of shares of Chord's stock on NASDAQ and regulatory clearances or approvals. Subject to the foregoing approvals, the Arrangement is expected to close by mid-year 2024.

12    ENERPLUS 2023 ANNUAL INFORMATION FORM

On February 21, 2024, the Board approved a dividend increase of 8% to its quarterly dividend to $0.065 per share beginning with the March 15, 2024 dividend. It is anticipated that the quarterly dividend payments made by Enerplus until closing of the transaction will be equalized to those made by Chord, after giving effect to the exchange ratio, through an additional Enerplus dividend declared shortly prior to the closing.

ENERPLUS 2023 ANNUAL INFORMATION FORM    13

Business of the Corporation

OVERVIEW

All of the Corporation's crude oil and natural gas property interests at December 31, 2023 are located in the United States, in North Dakota, Colorado and Pennsylvania. Capital spending on the Corporation’s assets in 2023 totaled $532.5 million.

Capital spending on the Corporation's Williston Basin and Colorado assets totaled $517.2 million during 2023. Capital spending on the Corporation's natural gas interests in northeast Pennsylvania was $15.3 million.

In 2023, the Corporation spent $15.0 million on abandonment and reclamation activities, $9.5 million of which related to the abandonment of its Tommy Lakes asset in British Columbia and the majority of the remaining $5.5 million was spent on the abandonment of the Joarcam property in Alberta.

Production volumes for the year ended December 31, 2023 from the Corporation's properties consisted of 62% crude oil and NGLs and 38% 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 2023 average daily production was 100,015 BOE/day, comprised of: 50,779 bbls/day of tight oil, 11,429 bbls/day of NGLs and 226,840 Mcf/day of shale gas. Approximately 64% of the Corporation's 2023 production was operated by the Corporation and the remainder operated by industry partners. Production in 2023 was similar to 2022 average production of 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 (totaling 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). See "Summary of Principal Production Locations". Enerplus’ average daily production in 2023 was in line with 2022 due to strong well performance from Enerplus' Bakken assets, which was offset by lower Marcellus production due to limited capital investment, and the sale of the Corporation’s remaining Canadian assets in the fourth quarter of 2022.

At December 31, 2023, the crude oil and natural gas property interests held by the Corporation were estimated to contain total proved plus probable gross reserves of 310.4 MMbbls of tight oil, 59.0 MMbbls of NGLs and 1,293.6 Bcf of shale gas, for a total of 585.1 MMBOE. The Corporation's proved reserves represented approximately 63% of total proved plus probable reserves, with approximately 63% 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, 2023, (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, 2023, all of the Corporation's gross production was derived from the United States (73% from North Dakota, 26% from Pennsylvania and 1% from Colorado, on a BOE basis).

The following table describes the average daily gross production from the Corporation's principal producing properties and regions during the year ended December 31, 2023.

2023 Average Daily Gross Production from Principal Properties and Regions⁽¹⁾

	Products
			Shale
Property/Region	Tight Oil	NGLs	Gas	Total, Gross
	(bbls/day)	(bbls/day)	(Mcf/day)	(BOE/day)
North Dakota	61,523	13,997	87,157	90,047
Marcellus, Pennsylvania	-	-	194,153	32,359
DJ Basin, Colorado	1,186	123	984	1,473
Total	62,709	14,120	282,294	123,879

(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.

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

14    ENERPLUS 2023 ANNUAL INFORMATION FORM

CAPITAL EXPENDITURES AND COSTS INCURRED

The Corporation invested $532.5 million in its capital spending program during 2023, with 97% directed to crude oil-related projects, approximately 23% higher than its 2022 capital spending program of $432.0 million. Capital spending during 2023 was focused primarily in the Corporation’s North Dakota Bakken crude oil property (with investment of $497.9 million). The Corporation’s Marcellus non-operated assets received capital investment of $15.3 million during the year. The remaining $19.3 million of capital was spent on the Corporation’s assets in the DJ Basin.

In the financial year ended December 31, 2023, the Corporation made the following expenditures in the United States in the categories noted, as prescribed by NI 51-101:

	Property Acquisition
	Costs				Exploration		Development
	Proved		Unproved		Costs		Costs
	(US$ in millions)
United States	$	7.3	$	-	$	1.8	$	530.7
Total	$	7.3	$	-	$	1.8	$	530.7

For further information regarding the Corporation's properties and its 2023 exploration and development activities, see "Description of Properties", below.

The Corporation's 2024 exploration and development capital spending is estimated to be $550 million based on a budgeted commodity price of $75 per barrel WTI for crude oil, $2.50 per Mcf NYMEX for natural gas and a foreign exchange rate of CDN/USD 0.75.

The Corporation intends to finance its 2024 capital spending program with cash, internally generated cash flow and/or debt. The Corporation will review its 2024 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, 2023, 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	141	64.7	-	-
Natural gas wells	57	1.2	-	-
Service wells	-	-	-	-
Dry and abandoned wells	-	-	-	-
Total	198	65.9	-	-

For a description of the Corporation's 2024 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, as at December 31, 2023, the Corporation's interests in producing wells and wells, all of which are located in the United States, 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 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
Colorado	44	16.8	-	-	13	0.8	-	-	22,032	20,480
North Dakota	1,449	811.1	-	-	59	38.4	-	-	5,705	2,640
Pennsylvania	-	-	1,174	110.8	-	-	56	5.6	21,365	5,516
Total	1,493	827.9	1,174	110.8	72	39.2	56	5.6	49,102	28,636

The Corporation expects its rights to explore, develop and exploit on approximately 839 net acres of its unproved properties to expire in the ordinary course prior to December 31, 2024. The Corporation has no material work commitments on its

ENERPLUS 2023 ANNUAL INFORMATION FORM    15

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 $517.2 million on its crude oil assets in 2023.

The Corporation has approximately 236,633 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 87% 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 72,925 BOE/day in 2023, which consisted of 49,827 bbls/day of tight oil, 11,323 bbls/day of NGLs and 70,645 Mcf/day of shale gas. During 2023, the Corporation spent $497.9 million on its operated and non-operated assets in North Dakota. This included drilling 61.8 net horizontal wells (54.7 operated and 7.1 non-operated), targeting the Bakken and Three Forks formations (all of which were long lateral wells), with 49.4 net wells brought on-stream (40.0 operated and 9.4 non-operated). At the end of 2023, the Corporation had 28.2 net operated drilled uncompleted wells in North Dakota.

The Corporation holds approximately 32,561 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 2023 was $19.3 million where Enerplus drilled 2.9 net operated wells and brought 3.1 net wells (2.9 operated and 0.2 non-operated) onstream. Average annual production for 2023 was 1,202 BOE/day (79% tight oil).

Overall, the Corporation's crude oil properties produced an average of 74,127 BOE/day in 2023, an increase of 3% from 2022 primarily due strong North Dakota production. On a BOE basis, production from crude oil properties represented 74% of the Corporation's 2023 average daily production of 100,015 BOE/day.

Approximately 33.0 MMBOE of gross proved plus probable reserves were added in North Dakota during 2023, including extensions, acquisitions, technical revisions and economic factors. After adjusting for 2023 gross production of 32.9 MMBOE, total gross proved plus probable reserves associated with this property as at December 31, 2023 were 422.9 MMBOE, approximately flat to December 31, 2022.

The Corporation had 425.2 MMBOE of gross proved plus probable reserves associated with its crude oil assets at December 31, 2023, representing approximately 73% 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.

16    ENERPLUS 2023 ANNUAL INFORMATION FORM

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 31,950 net acres. The Corporation's Marcellus shale gas production averaged 155 MMcf/day in 2023, representing approximately 26% of the Corporation's total average daily production of 100,015 BOE/day.

In 2023, $15.3 million was invested in the Corporation's non-operated Marcellus interests. The Corporation participated in the drilling of 1.2 net wells and 0.9 net wells were brought on-stream.

Gross proved plus probable Marcellus shale gas reserves were 958.9 Bcf as at December 31, 2023, a decrease of 86.9 Bcf from 2022, and represented approximately 27% 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.

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 2023 and for the entire year. All of the Corporation’s production was derived from its properties in the United States.

	Year Ended December 31, 2023
	First	Second	Third	Fourth
Product Type	Quarter	Quarter	Quarter	Quarter	Annual
Tight oil (bbls/day)	58,528	58,664	66,833	66,678	62,709
Total crude oil (bbls/day)	58,528	58,664	66,833	66,678	62,709
Natural gas liquids (bbls/day)	11,595	13,338	15,404	16,079	14,120
Total liquids (bbls/day)	70,123	72,002	82,237	82,757	76,829
Shale gas (Mcf/day)	305,685	279,113	272,982	271,864	282,294
Total (BOE/day)	121,071	118,521	127,734	128,068	123,879

(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 2023 ANNUAL INFORMATION FORM    17

QUARTERLY NETBACK HISTORY

The following tables set forth the Corporation's average netbacks received on a gross basis for each fiscal quarter in 2023 and for the entire year. Netbacks are calculated on the basis of prices received but before the effects of commodity derivative instruments, less related transportation, 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, 2023
	First		Second		Third		Fourth
Tight Oil (US$ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
Sales price(1)	$	76.89	$	73.08	$	82.77	$	77.54	$	77.75
Transportation		(4.40)		(3.96)		(3.92)		(3.97)		(4.05)
Royalties(2)		(20.77)		(19.57)		(21.94)		(20.65)		(20.77)
Production costs(3)		(17.06)		(16.10)		(15.24)		(17.70)		(16.52)
Netback	$	34.66	$	33.45	$	41.67	$	35.22	$	36.41

	Year Ended December 31, 2023
	First		Second		Third		Fourth
Natural Gas Liquids (US$ per bbl)	Quarter		Quarter		Quarter		Quarter		Annual
Sales price(1)	$	20.94	$	15.67	$	19.52	$	17.29	$	18.26
Transportation		(0.45)		(0.37)		(0.33)		(0.33)		(0.36)
Royalties(2)		(4.37)		(3.22)		(4.03)		(3.59)		(3.78)
Production costs(3)		-		—		—		—		—
Netback	$	16.12	$	12.08	$	15.16	$	13.37	$	14.12

	Year Ended December 31, 2023
	First		Second		Third		Fourth
Shale Gas (US$ per Mcf)	Quarter		Quarter		Quarter		Quarter		Annual
Sales price(1)	$	3.23	$	1.17	$	1.43	$	1.69	$	1.91
Transportation		(0.51)		(0.50)		(0.49)		(0.47)		(0.49)
Royalties(2)		(0.71)		(0.34)		(0.40)		(0.44)		(0.48)
Production costs(3)		(0.09)		(0.12)		(0.09)		(0.09)		(0.10)
Netback	$	1.92	$	0.21	$	0.45	$	0.69	$	0.84

Notes:

(1) Before the effects of commodity derivative instruments.

(2) Includes production taxes.

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

TAX HORIZON

The Corporation is subject to standard applicable corporate income taxes. Based on existing tax legislation, the Corporation's available tax pools, expected capital spending and forecasted net income, the Corporation does not anticipate paying cash taxes in Canada until 2028. 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 12 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.sedarplus.ca and on the Corporation's EDGAR profile at www.sec.gov.

18    ENERPLUS 2023 ANNUAL INFORMATION FORM

MARKETING ARRANGEMENTS AND FORWARD CONTRACTS

Crude Oil and NGLs

The Corporation’s realized crude oil price averaged $77.42/bbl and $17.93/bbl for its NGLs for the year ended December 31, 2023, excluding transportation costs and the effects of commodity derivative instruments, compared to $93.63/bbl for its crude oil and $30.70/bbl for its NGLs for the year ended December 31, 2022.

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 2023, the Corporation received an average price differential for its U.S. Bakken crude oil of $0.45/bbl below WTI, compared to an average of $1.09/bbl above WTI in 2022. The Corporation has access to firm transportation of 22,550 gross barrels per day on the 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 2023, 68% 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 2023 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 seven 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 2025 and 2036.

The Corporation’s realized natural gas price averaged $1.85/Mcf in 2023, excluding transportation costs and the effects of commodity derivative instruments, compared to $5.51/Mcf in 2022. In 2023, the Corporation received an average price differential for its U.S. Marcellus shale gas production of $0.92/Mcf below NYMEX compared to an average of $0.72/Mcf below NYMEX in 2022. Approximately 32% 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 14 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.sedarplus.ca and on the Corporation's EDGAR profile at www.sec.gov.

ENERPLUS 2023 ANNUAL INFORMATION FORM    19

Oil and Natural Gas Reserves

SUMMARY OF RESERVES

As at December 31, 2023, all of the Corporation's crude oil and natural gas reserves were 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, 2024 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, 2024 to prepare its report.

The following sections and tables summarize, as at December 31, 2023, 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, 2022 to December 31, 2023, 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.

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 as at December 31, 2023, using forecast price and cost cases.

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

As of December 31, 2023

			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	84,951	68,255	18,507	14,894	682,666	550,699	217,235	174,933
Proved Developed Non-Producing	1,059	861	125	102	11,233	9,116	3,057	2,482
Proved Undeveloped	91,362	73,142	15,865	12,699	252,239	204,186	149,267	119,872
Total Proved	177,372	142,258	34,497	27,695	946,138	764,002	369,559	297,287
Probable	133,072	106,680	24,522	19,684	347,434	283,868	215,500	173,675
Total Proved Plus Probable	310,444	248,938	59,019	47,379	1,293,572	1,047,871	585,059	470,962

20    ENERPLUS 2023 ANNUAL INFORMATION FORM

Summary of Net Present Value of Future Net Revenue

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

As of December 31, 2023

	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	3,520	2,860	2,411	2,096	1,865	2,843	2,340	1,978	1,721	1,530		$13.78
Proved Developed Non‑Producing	51	40	33	28	24	39	31	25	21	18		$13.40
Proved Undeveloped	2,500	1,881	1,453	1,150	929	1,882	1,412	1,084	852	684		$12.12
Total Proved	6,071	4,781	3,897	3,275	2,818	4,763	3,783	3,087	2,595	2,233		$13.11
Probable	4,966	3,018	2,028	1,461	1,109	3,772	2,271	1,507	1,073	807		$11.67
Total Proved Plus Probable	11,037	7,799	5,925	4,736	3,927	8,536	6,054	4,594	3,668	3,040		$12.58

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, 2024 (utilized by McDaniel and NSAI 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)
2024	73.67	2.75	0.0	0.752
2025	74.98	3.64	2.0	0.752
2026	76.14	4.02	2.0	0.755
2027	77.66	4.10	2.0	0.755
2028	79.22	4.18	2.0	0.755
2029	80.80	4.27	2.0	0.755
2030	82.42	4.35	2.0	0.755
2031	84.06	4.44	2.0	0.755
2032	85.74	4.53	2.0	0.755
2033	87.46	4.62	2.0	0.755
2034	89.21	4.71	2.0	0.755
2035	90.99	4.81	2.0	0.755
2036	92.81	4.90	2.0	0.755
2037	94.67	5.00	2.0	0.755
2038	96.56	5.10	2.0	0.755
Thereafter	(2)	(2)	2.0	0.755

Notes:   

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

(2) Escalation is approximately 2% per year thereafter

In 2023, the Corporation received a weighted average price (before transportation costs and the effects of commodity derivative instruments) of $77.42/bbl for crude oil, $17.93/bbl for natural gas liquids and $1.85/Mcf for natural gas.

ENERPLUS 2023 ANNUAL INFORMATION FORM    21

UNDISCOUNTED FUTURE NET REVENUE BY RESERVES CATEGORY

The undiscounted total future net revenue by reserves category as of December 31, 2023, 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	17,046	4,475	4,452	1,628	420	6,071	1,307	4,763
Proved Plus Probable Reserves	30,091	7,990	7,356	3,170	538	11,037	2,501	8,536

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, 2023, 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)	$	3,334,709	$	23.44
	Shale Gas(3)		562,359		0.95
	Total	$	3,897,068
Proved Plus Probable Reserves	Tight Oil(2)	$	5,269,040	$	21.17
	Shale Gas(3)		655,589		0.85
	Total	$	5,924,629

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 2024 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual 2024 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 2024		Estimated 2024
	Aggregate		Average Daily
Product Type	Production		Production
Crude Oil
Tight Oil	24,128	Mbbls	65,924	bbls/day
Total Crude Oil	24,128	Mbbls	65,924	bbls/day
Natural Gas Liquids	4,299	Mbbls	11,746	bbls/day
Total Liquids	28,427	Mbbls	77,670	bbls/day
Shale Gas	97,445	MMcf	266,243	Mcf/day
Total	44,668	MBOE	122,044	BOE/day

22    ENERPLUS 2023 ANNUAL INFORMATION FORM

	Gross Probable Reserves
	Estimated 2024		Estimated 2024
	Aggregate		Average Daily
Product Type	Production		Production
Crude Oil
Tight Oil	2,549	Mbbls	6,963	bbls/day
Total Crude Oil	2,549	Mbbls	6,963	bbls/day
Natural Gas Liquids	449	Mbbls	1,228	bbls/day
Total Liquids	2,998	Mbbls	8,191	bbls/day
Shale Gas	3,949	MMcf	10,791	Mcf/day
Total	3,656	MBOE	9,990	BOE/day

The tables below set forth McDaniel's and NSAI’s estimated 2024 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 2024 production.

	Gross Proved Reserves
	North Dakota				Marcellus
	Estimated 2024		Estimated 2024		Estimated 2024		Estimated 2024
	Aggregate		Average Daily		Aggregate		Average Daily
Product Type	Production		Production		Production		Production
Crude Oil
Tight Oil	23,821	Mbbls	65,085	bbls/day	-	Mbbls	-	bbls/day
Total Crude Oil	23,821	Mbbls	65,085	bbls/day	-	Mbbls	-	bbls/day
Natural Gas Liquids	4,272	Mbbls	11,672	bbls/day	-	Mbbls	-	bbls/day
Total Liquids	28,093	Mbbls	76,757	bbls/day	-	Mbbls	-	bbls/day
Shale Gas	26,589	MMcf	72,646	Mcf/day	70,648	MMcf	193,028	Mcf/day
Total	32,524	MBOE	88,865	BOE/day	11,775	MBOE	32,171	BOE/day

	Gross Probable Reserves
	North Dakota				Marcellus
	Estimated 2024		Estimated 2024		Estimated 2024		Estimated 2024
	Aggregate		Average Daily		Aggregate		Average Daily
Product Type	Production		Production		Production		Production
Crude Oil
Tight Oil	2,508	Mbbls	6,851	bbls/day	-	Mbbls	-	bbls/day
Total Crude Oil	2,508	Mbbls	6,851	bbls/day	-	Mbbls	-	bbls/day
Natural Gas Liquids	445	Mbbls	1,215	bbls/day	-	Mbbls	-	bbls/day
Total Liquids	2,952	Mbbls	8,066	bbls/day	-	Mbbls	-	bbls/day
Shale Gas	2,699	MMcf	7,373	Mcf/day	1,214	MMcf	3,316	Mcf/day
Total	3,402	MBOE	9,295	BOE/day	202	MBOE	553	BOE/day

FUTURE DEVELOPMENT COSTS

The amount of development costs deducted in the estimation of net present value of future net revenue is set forth below. The Corporation intends to fund its development activities through cash, internally generated cash flow and/or debt. The Corporation does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on the Corporation's disclosed oil and gas reserves or future net revenue attributable to those reserves. For additional information, see "Business of the Corporation – Capital Expenditures and Costs Incurred".

			Proved Plus
	Proved Reserves		Probable Reserves
		Discounted		Discounted
Year	Undiscounted	at 10%/year	Undiscounted	at 10%/year
	(in US$ millions)
2024	411	396	411	396
2025	479	416	479	416
2026	436	344	436	344
2027	301	218	400	287
2028	1	1	435	284
2029	-	-	403	239
Remainder	-	-	606	322
Total	1,628	1,374	3,170	2,287

ENERPLUS 2023 ANNUAL INFORMATION FORM    23

RECONCILIATION OF RESERVES

Overview

The Corporation's total gross proved plus probable reserves at December 31, 2023 were 585.1 MMBOE, a decrease of 3% from year-end 2022. The Corporation's gross proved plus probable crude oil and NGLs reserves were 369.5 MMBOE and represented 63% of total proved plus probable gross reserves, a decrease of 1% from year-end 2022. The Corporation replaced approximately 69% of its 2023 gross production through its exploration and development program, adding 31.1 MMBOE of proved plus probable reserves, including revisions and economic factors. Of the Corporation’s 31.1 MMBOE of proved plus probable additions, including revisions and economic factors, 33.0 MMBOE are attributed to the North Dakota properties and -2.7 MMBOE (-16.1 Bcf) to the Marcellus shale gas property. The following tables reconcile the Corporation's gross crude oil and natural gas reserves from December 31, 2022 to December 31, 2023, all of which are associated with its properties located in the United States, using forecast prices and costs. Certain columns may not add due to rounding.

GROSS OIL AND GAS RESERVES

	Tight Oil			Natural Gas Liquids
			Proved			Proved
			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
December 31, 2022	180,273	136,863	317,136	32,592	23,743	56,335
Acquisitions	-	-	-	-	-	-
Dispositions	(1,205)	(269)	(1,474)	(151)	(47)	(199)
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	32,235	9,972	42,207	4,856	419	5,275
Economic Factors	(208)	(32)	(240)	(92)	(20)	(112)
Technical Revisions	(10,834)	(13,463)	(24,296)	2,446	428	2,873
Production	(22,889)	-	(22,889)	(5,154)	-	(5,154)
December 31, 2023	177,372	133,072	310,444	34,497	24,522	59,019

	Shale Gas			Total
			Proved			Proved
			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable
	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)	(MBOE)
December 31, 2022	1,074,204	291,704	1,365,908	391,899	209,224	601,123
Acquisitions	-	-	-	-	-	-
Dispositions	(1,366)	(360)	(1,726)	(1,585)	(376)	(1,961)
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	45,202	19,617	64,819	44,625	13,660	58,285
Economic Factors	(7,812)	960	(6,852)	(1,602)	108	(1,494)
Technical Revisions	(61,052)	35,512	(25,540)	(18,563)	(7,116)	(25,680)
Production	(103,037)	-	(103,037)	(45,215)	-	(45,215)
December 31, 2023	946,138	347,434	1,293,572	369,559	215,500	585,059

24    ENERPLUS 2023 ANNUAL INFORMATION FORM

NET OIL AND GAS RESERVES

	Tight Oil (NET)			Natural Gas Liquids (NET)
			Proved			Proved
			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
December 31, 2022	144,684	109,661	254,345	26,179	19,036	45,215
Acquisitions	-	-	-	-	-	-
Dispositions	(965)	(215)	(1,180)	(121)	(38)	(159)
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	25,767	8,071	33,838	3,882	366	4,248
Economic Factors	(167)	(24)	(192)	(74)	(16)	(90)
Technical Revisions	(8,529)	(10,812)	(19,341)	1,998	335	2,334
Production	(18,532)	-	(18,532)	(4,170)	-	(4,170)
December 31, 2023	142,258	106,680	248,938	27,695	19,684	47,379

	Shale Gas (NET)			Total (NET)
			Proved			Proved
			Plus			Plus
Factors	Proved	Probable	Probable	Proved	Probable	Probable
	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)	(MBOE)
December 31, 2022	863,419	237,802	1,101,221	314,766	168,331	483,097
Acquisitions	-	-	-	-	-	-
Dispositions	(1,094)	(288)	(1,381)	(1,268)	(301)	(1,569)
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	40,556	17,117	57,674	36,409	11,289	47,698
Economic Factors	(4,790)	769	(4,021)	(1,039)	88	(951)
Technical Revisions	(51,315)	28,468	(22,847)	(15,083)	(5,732)	(20,815)
Production	(82,775)	-	(82,775)	(36,498)	-	(36,498)
December 31, 2023	764,002	283,868	1,047,871	297,287	173,675	470,962

UNDEVELOPED RESERVES

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

Proved Undeveloped Reserves

	Crude Oil
			Shale
Year(1)	Tight	NGLs	Gas	Total
	(Mbbls)	(Mbbls)	(MMcf)	(MBOE)
2021	28,182	4,784	108,948	51,124
2022	17,736	2,790	56,814	29,995
2023	29,703	4,789	37,879	40,805

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)
2021	12,641	2,106	38,135	21,103
2022	23,846	3,953	68,264	39,176
2023	9,480	396	18,146	12,900

Note:

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

ENERPLUS 2023 ANNUAL INFORMATION FORM    25

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, 2023 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 North Dakota, the Corporation has been active for the last several years in drilling and developing these undeveloped reserves, converting the associated volumes to producing reserves. The Corporation has, in the past, maintained the gross proved plus probable undeveloped location well count year over year and added undeveloped locations to replace those that were drilled in the preceding year. The Corporation has increased the gross proved plus probable undeveloped location count from 494 locations in 2022 to 527 locations as of December 31, 2023. 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 2023, the Corporation continued to participate in the development of its non-operated undeveloped reserves in the Marcellus property, converting 1.1 net proved plus probable locations to developed reserves. These converted locations were replaced with additions of 2.4 net proved plus probable undeveloped locations as of December 31, 2023. Development timing for both proved undeveloped and probable undeveloped locations is based on recent activity and scheduling prepared by the operators of the properties. 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 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 “Risk Factors – 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 3.7 MMBOE (1.9 MMBOE in its crude oil properties and 1.9 MMBOE (11.1 Bcf) in its natural gas properties) of proved plus probable reserves which are capable of production but which, as of December 31, 2023, 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 (30 wells) and Pennsylvania (25 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 2027.

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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 President & Chief Executive Officer and the Board are ultimately accountable for overseeing compliance with both policies. The Corporation's management and its corporate sustainability department are responsible for communicating and integrating these policies 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, sustainability targets are factored into the bonus structure applied to all executives and employees. Tying environmental and social 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 key 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 GHG emissions and water management, health and safety and community engagement. Oversight of the final key 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 key focus areas which have the potential to become significant for Enerplus in the future: supply chain management, technology advancement/digitization, biodiversity and industry advocacy. In addition, Enerplus has identified areas of previous focus which are now considered to be “maintaining” areas of focus as a result of an understanding and development of processes around them; these include board constitution and culture, cyber security, liability management, 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 being a good steward 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 performance.

The H&S Policy discusses the Corporation's commitment to protect the health and safety of all persons and communities involved in our operations and the environment, people and communities where we operate. Specifically, the H&S Policy discusses the Corporation’s approach to H&S matters, which include the Corporation’s goals to:

● Apply a culture of accountability 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

● 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 further the goal of keeping people safe while delivering operational excellence

The ESG Policy reiterates the Corporation's commitment to sustainability and discusses the Corporation’s approach to ESG matters, which include its goals to:

●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 associated with its operations, where practicable

●Limit the waste generated in connection with its operations

●Prevent and manage releases with its operations, where practicable

●Monitor its environmental performance and provide transparent disclosure

● Improve its environmental management system on an ongoing basis, where practicable, and provide resources and training to improve its capability to meet and exceed environmental commitments

●Comply with all applicable rules and regulations

●Invest in building and sustaining positive relationships with its stakeholders

●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

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The Corporation's commitment to building meaningful and transparent relationships with its stakeholders is reflected in its 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 with reference to the Sustainability Accounting Standards Board (SASB), the Global Reporting Initiatives (GRI) 11: Sector Standard for Oil and Gas disclosure 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 provides American Exploration & Production Council (AXPC) reporting. The ESG report and data tables 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, 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 in 2023 was 0.36 per 200,000 worker hours, a decrease from the rate of 0.60 recorded in 2022. The Corporation had an employee recordable injury frequency rate of nil per 200,000 worker hours in 2023, a decrease from the rate of 0.23 per 200,000 worker hours in 2022. The Corporation's total contractor recordable injury frequency was 0.44 per 200,000 worker hours in 2023, a decrease from 0.73 injuries per 200,000 worker hours in 2022. The Corporation recorded one lost-time injury in each of 2023 and 2022. As a key 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 79%.

Health and safety risks influence workplace practices, operating costs and the establishment of health and safety standards. 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 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 be a good steward of 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 2023 totaled approximately $15.0 million, including $9.5 million on its Tommy Lakes asset. The majority of the remaining $5.5 million was spent on the Joarcam property in Alberta.  

● Government regulators conducted 127 inspections of the Corporation’s field operations in the United States in 2023, an increase compared to the prior year’s 98 government regulator inspections, inclusive of Canadian assets owned at the time. The percentage of non-compliant inspections received by the Corporation in 2023 increased to 21%, compared to 19% received in 2022.

● The Corporation conducts an internal site inspection program to proactively assess environmental, regulatory and general housekeeping items. Findings from the internal site inspection program and any action items are recorded in the Corporation’s internal reporting platforms in order to measure compliance and ensure potential issues are addressed.

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● In 2023, the Corporation completed a total of 1,129 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, and in 2023 continued using technology to treat water in real-time on location.

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, 2023 for the 2022 operational year. For more information on the environmental regulation applicable to the Corporation, see "Industry Conditions – Environmental Regulation".

Enerplus has made meaningful progress in reducing its Scope 1 and Scope 2 GHG emissions intensity through improved operational processes and planning, and investment in emissions reduction projects. The Corporation now expects to exceed its 2030 Scope 1 Emissions and Scope 2 Emissions intensity reduction target in 2023 (which is expected to be confirmed in the second quarter of 2024), expected to represent an approximate reduction of 43% from the 2021 baseline. Enerplus is also tracking ahead of its existing methane intensity reduction targets in 2023, where it expects to achieve an approximate 46% reduction from the 2021 baseline. The Corporation spent approximately $10 million on its GHG emissions reduction initiatives in 2023.

As a result of the outperformance noted above, Enerplus has revised its GHG and methane emissions intensity targets as follows:

● Scope 1 Emissions intensity of 7 kg CO2e/BOE by 2030; an approximate 60% reduction from 2023 estimates

● Scope 1 Emissions & Scope 2 Emissions intensity of 13 kg CO2e/MBOE by 2030; an approximate 30% reduction from 2023 estimates

● Methane emissions intensity of 0.02 kg CH4/MBOE by 2030; an approximate 45% reduction from 2023 estimates

In addition, Enerplus is endorsing the World Bank Zero Routine Flaring by 2030 initiative and has established a flare intensity target of less than 2% per thousand cubic feet of natural gas produced by 2026.

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 demonstrate its ongoing commitment to environmental stewardship and the health and safety of its employees, contractors and the general public in the communities in which it operates. Annually, the Corporation identifies key 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 key focus areas, the Corporation will continue to improve its corporate sustainability 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 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, 2023, the Corporation employed a total of 404 persons, including full-time benefit employees and payroll consultants, 156 of whom were in Canada and 248 of whom were in the United States.

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Description of Capital Structure

The authorized capital of the Corporation consists of an unlimited number of Common Shares, and a number of preferred shares issuable in series ("Preferred Shares"), which are limited to an amount equal to not more than one-quarter of the number of issued and outstanding Common Shares at the time of the issuance of any such Preferred Shares. The following is a summary of the rights, privileges, restrictions and conditions attaching to the Common Shares and the Preferred Shares. Copies of the Corporation's Articles, 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.sedarplus.ca 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 Board 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 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. Effective September 19, 2014, the Board suspended the 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 Board. 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 $122.6 million principal amount was outstanding as at December 31, 2023. 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$63 million	3.79	%	March 3 and September 3	September 3, 2026	Remaining principal payments required in three equal annual installments beginning September 3, 2024
May 15, 2012	US$355 million	US$59.6 million	4.40	%	May 15	May 15, 2024	Remaining principal payment required on May 15, 2024

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

SLL CREDIT FACILITIES

As at December 31, 2023, the Corporation had $43.8 million drawn on its $900 million SLL Credit Facility, and $19.6 million 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 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.

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For a description of the SLL Credit Facilities, see disclosure under the heading “Liquidity and Capital Resources” in the MD&A and Note 7 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

The Board 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 Board 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.

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

During 2023, the Corporation declared the following quarterly dividends:

● Q1 2023 – US$0.055 per share, paid on March 15

● Q2 2023 – US$0.055 per share, paid on June 15

● Q3 2023 – US$0.060 per share, paid on September 15

● Q4 2023 – US$0.060 per share, paid on December 15

On February 21, 2024, Enerplus declared an increase of 8% to its quarterly dividend to US$0.065] per share, payable on March 15, 2024. It is anticipated that the quarterly dividend payments made by Enerplus until closing of the transaction will be equalized to those made by Chord, after giving effect to the exchange ratio, through an additional Enerplus dividend declared shortly prior to the closing. See "General Development of the Business – Developments in the Past Three Years – Recent Developments".

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".

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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 U.S. states of 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 within 270 days after the end of the fiscal year, 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.

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 natural gas prices continued to be volatile during 2023 in response to a variety of factors including, among others, supply

32    ENERPLUS 2023 ANNUAL INFORMATION FORM

and demand impacts due to the prolonged conflict in Ukraine, and more recent unrest in the Middle East, as well as ongoing concerns over crude oil demand due to the potential impact of a global recession, and 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"). In addition, the Federal Trade Commission (“FTC”) has the authority under the Federal Trade Commission Act and the Energy Independence and Security Act of 2007 to regulate wholesale petroleum markets. 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, the CFTC and/or the FTC. These agencies hold substantial enforcement authority, including the ability to assess or seek civil penalties of up to $1,544,521 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

United States

The Corporation is subject to the applicable municipal, tribal, state and federal environmental laws and regulations in its operating areas in the United States. 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, as well as public opposition and activism”.

At the U.S. 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.

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Additional regulations affecting the Corporation's U.S. operations include: (i) the Federal Implementation Plan for Oil and Natural Gas Well Production Facilities, FBIR (Mandan, Hidatsa, and Arikara Nations) (the "MHA Nation"), in North Dakota and (ii) the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. These regulations provide emission control requirements for the Corporation's U.S. assets, as well as increased monitoring, recordkeeping, reporting and regulatory oversight. 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 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 asserted that this decision was incorrect and sought to intervene in the litigation, which the district court denied. The state of North Dakota appealed the denial to the United States Court of Appeals for the District of Columbia and, in April 2023, the Court of Appeals reversed and remanded the district court’s decision. In July 2023, the district court granted North Dakota’s right to intervene. The litigation remains pending at this time, and, as such, 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, 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. See “Climate-Change Related Legislation” for further discussion on the

EPA’s new, finalized methane rules.

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. The enforceable gas capture percentage goal is currently 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, 2023, the Corporation was continuing to capture approximately 96% of its natural gas production in North Dakota.

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 state’s oil and gas laws, 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. The COGCC has implemented regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these

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regulations establish more stringent setbacks on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, additional restrictions for oil and gas activities, such as requiring greater setbacks. Additionally, the Colorado Air Quality Control Commission has adopted regulations aimed at curbing methane emissions from oil and gas operations to include setting methane emission limits, more frequent inspections, limits on emissions during maintenance and requiring direct measurement of such emissions.

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. The Corporation endeavours 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 majority of the required abandonment work was completed in 2023, with some additional ongoing work on reclamation and remediation continuing through 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 began abandonment work on an Alberta 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 began 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 developed voluntary disclosure under a singular, accessible framework specific to climate change-related actions and provided the fundamental framework upon which rules proposed by the International Sustainability Standards Board (“ISSB”) and the Securities and Exchange Commission (“SEC”) and Canadian securities regulatory authorities on climate-related disclosures are based. In late 2023, the ISSB announced it was taking over the responsibility of TCFD. Enerplus continues to recognize the TCFD recommended guidelines and is working toward integrating fit for purpose disclosure from the guidelines, and also considering International Financial Reporting Standards S1 and S2, into its disclosure strategy. The TCFD Aligned Reporting Table in connection with Enerplus’ 2023 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-

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wide net GHG emissions 50% to 52% below 2005 levels by 2030. Additionally, at the 26th Conference of the Parties to the UN Framework Convention on Climate Change (“COP”) 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. At COP28 in Dubai in December 2023, among other initiatives to increase renewable energy capacity and further reduce methane emissions, the participating countries issued a statement that they must “transition away from fossil fuels in energy systems, in a just, orderly and equitable manner” in an effort to achieve “net zero by 2050.

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, but the U.S. EPA finalized more stringent rules for new, modified and reconstructed facilities, known as OOOOb, as well as standards for existing sources, known as OOOOc, in December 2023. Under the final rules, U.S. states have two years to prepare and submit their plans to impose methane emissions controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to the U.S. EPA of large methane emissions events, triggering certain investigation and repair requirements. It is likely, however, that the final rule and its requirements will be subject to legal challenges. The requirements of the U.S. EPA’s final methane rules could increase the Corporation’s operating costs and reduce the demand for its services, thereby adversely affecting its operations and potentially restricting

or delaying the Corporation’s ability to obtain applicable permits, approvals or certificates for new or modified facilities. Moreover, failure to comply with the requirements could result in the imposition of substantial fines and penalties, as well

as costly injunctive relief.

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 also likely that this rule will be subject to legal challenges, though the Corporation cannot predict how this may affect implementation. To the extent finalized as proposed, this rule could increase its operating costs, limit operations in certain areas, or otherwise adversely impact the Corporation’s 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. Compliance with the U.S. EPA’s finalized methane rules would, however, exempt an otherwise covered facility from the requirement to pay the methane emissions fee. 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/or compliance with initiatives that target the oil and gas industry, 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 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.

ENERPLUS 2023 ANNUAL INFORMATION FORM    37

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 or the amount of dividends that may, from time to time and at the discretion of the Board, be declared and paid by the Corporation to its shareholders. In addition, the Arrangement Agreement restricts Enerplus from taking specified actions until the Arrangement is completed, without the consent of Chord. Therse restrictions may prevent Enerplus from pursuing attractive business opportunities that may arise or otherwise affect how Enerplus conducts its business prior to completion of the Arrangement. In addition, some of the risks set forth below may become more prominent as a result of the proposed Arrangement and the terms and nature of the Arrangement and the consideration offered to Enerplus shareholders.

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

The Corporation may be unable to satisfy the condition precedents of the Arrangement Agreement in a timely manner, or at all.

The completion of the Arrangement is subject to a number of conditions precedents, certain of which are outside the control of the Corporation, including obtaining the requisite approvals from the Enerplus and Chord shareholders and the Court of King's Bench of Alberta, the listing of Chord's stock on NASDAQ and regulatory clearances or approvals. There is no certainty, nor can Enerplus provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied. A substantial delay in obtaining satisfactory approvals or the imposition of unfavourable terms or conditions by a governmental entity or regulator may adversely affect the business, financial condition or results of operations of Enerplus or the combined company following the completion of the Arrangement. If for any reason the Arrangement is not completed, or is materially delayed, the market price of the Common Shares and/or the shares of Chord common stock may be adversely affected. If the Arrangement Agreement is terminated and the Arrangement is not completed, there is no assurance that the Corporation will be able to complete a similar transaction.

Even if all approvals, orders and consents are obtained and conditions precedent to the completion of the Arrangement are satisfied, no assurance can be made as to the terms, conditions and timing of such approvals, orders and consents. These approvals, orders and consents may impose conditions on or require divestitures relating to the divisions, operations or assets of Enerplus and/or Chord or may impose requirements, limitations or costs or place restrictions on the conduct of Enerplus' or Chord's respective businesses, and if such approvals, orders or consents require an extended period of time to be obtained, such extended period of time could increase the chance that an adverse event occurs with respect to Enerplus or Chord. Such extended period of time may also increase the chance that other adverse effects with respect to Enerplus and/or Chord could occur, such as the loss of key personnel. Each party's obligation to complete the Arrangement is also subject to the accuracy of the representations and warranties of the other party (subject to certain qualifications and exceptions) and the performance in all material respects of the other party's covenants under the Arrangement Agreement. As a result of these conditions, the parties cannot provide assurance that the Arrangement will be completed on the terms or timeline contemplated in the Arrangement Agreement, or at all.

The Corporation may fail to realize the anticipated benefits of the Arrangement.

Enerplus and Chord are proposing to complete the Arrangement to create a larger operator in the Williston Basin and the opportunity to realize certain anticipated benefits, including, among other things, increased scale and high-quality inventory, potential synergies and cost savings. The Arrangement is subject to normal commercial risks that such transaction may not be completed on the terms negotiated or at all. Achieving the benefits of the Arrangement depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the combined company's ability to realize the anticipated growth opportunities and synergies from integrating the respective businesses of Enerplus and Chord following completion of the Arrangement. There can be no assurance that such benefits will occur in a timely manner or at all.

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 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

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

● geopolitical uncertainty, including for example, the impact of the conflicts in Ukraine and the Middle East; the risk of international hostile actions, as well as actions in the United States or Canada that could disrupt trade or other relations

● 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, fractionation and transportation 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, as well as volatility in the political, legal and regulatory environments ahead of, and in connection with, the upcoming U.S. presidential election

● sustained pandemics or epidemics, which may disrupt economies, whether local or global, and may impact

supply, demand or commodity prices for crude oil, NGLs or natural gas

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, dividend payments 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.

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

The Corporation adds to its oil and natural gas reserves primarily through acquisitions and ongoing development of its existing reserves and resources, together with certain exploration activities. As a result, the level of the Corporation's future oil and natural gas reserves is highly dependent on its success in developing and exploiting its reserves and resources base and acquiring additional reserves and/or resources through purchases or exploration. Exploitation, exploration and development risks arise for the Corporation and, as a result, may affect the value of the Common Shares and dividends to shareholders due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. Additionally, if capital from external sources is not available or is not available on commercially advantageous terms, the Corporation's ability to make the necessary capital investments to maintain, develop or expand its oil and natural gas reserves and resources will be impaired. Even if the necessary capital is available, the Corporation cannot assure that it will be successful in acquiring additional reserves or resources on terms that meet its investment objectives. Without these additions, the Corporation's reserves will deplete and, as a consequence, either its production or the average life of its reserves will decline.

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

ENERPLUS 2023 ANNUAL INFORMATION FORM    39

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”.

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

The Corporation is permitted under the Arrangement Agreement to pursue certain acquisitions and divestments. As a result, 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.

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.

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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 that are permitted under the terms of the Arrangement Agreement. 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 and that are permitted under the terms of the Arrangement Agreement. Any of the acquisitions, dispositions or other corporate actions may require the dedication of substantial management effort, time and capital and other resources, which may divert management's focus, capital and other resources from other strategic opportunities and operational matters during the process. Although certain substantial acquisitions, business combinations or other corporate transactions, such as a potential re-domicile of the Corporation to another jurisdiction or a share consolidation, for example, could also be subject to approval by a certain majority of the Corporation’s shareholders, the Corporation may not achieve the intended or anticipated favourable results of such actions and may result in adverse consequences to certain or all of the Corporation’s stakeholders, including its shareholders.

See also "The Corporation may be unable to satisfy the condition precedents of the Arrangement Agreement in a timely manner, or at all" and "The Corporation may fail to realize the anticipated benefits of the Arrangement" above.

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 increase its operating costs when the benchmarks rise significantly, including in the recent high-inflation environment.

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 negatively 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.

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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, but particularly in the oil and gas industry, are facing increasing scrutiny from government and stakeholders related to their ESG and sustainability practices. The societal, investor, and regulatory expectations on

companies relating to ESG matters, including climate change and other environmental and social impacts are evolving, and if the Corporation fails to comply with or meet such expectations, or are perceived to have not responded appropriately, 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 share price of the Corporation could be materially and adversely affected. Increasing attention to climate change and sustainability-related matters, increasing societal expectations on companies to address climate change, including setting and achieving climate-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, negative impacts on the Corporation's share price and reduced access to capital markets and cause the market to prioritize sustainability initiatives over corporate results. 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 litigation against the Corporation. To the extent that societal pressures, regulatory, or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Some capital markets participants are increasingly using certain components of ESG as a factor in their assessments, which could impact the Corporation’s cost of capital or access to financing. There has also been an acceleration in investor demand for ESG investing opportunities, and many institutional investors have committed to increasing the percentage of

their portfolios that are allocated towards ESG-focused investments. As a result, there has been a proliferation of ESG focused investment funds and market participants seeking ESG-oriented investment products. There has also been an increase in third-party providers of company ESG ratings and rankings, and an increase in ESG-focused voting policies among proxy advisory firms, portfolio managers, and institutional investors. For example, 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 ratings, rankings and voting policies, they often differ based on the provider and the data they prioritize and are continually changing. However, such ratings, rankings and voting policies may be used by some investors to inform their investment and voting decisions. Additionally, certain investors may use these ratings or rankings to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage with the Corporation to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability rating or ranking as a reputational or other factor in making an investment decision. Consequently, a low sustainability rating or ranking could result in exclusion of the Corporation’s shares from consideration by certain investment funds, engagement by investors seeking to improve such ratings or rankings 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. Furthermore, there has recently been backlash from certain governments and investors against ESG funds and investment practices, which has resulted in increased scrutiny and withdrawals from such funds. Such backlash has also resulted in “anti-ESG” focused activism and investment funds, which may result in additional strains on the Corporation’s resources. If Enerplus is unable to meet the often conflicting ESG standards or investment, lending, ratings, or voting criteria and policies set by these parties, it may lose investors, investors may choose not to allocate a portion of their capital to the Corporation, it may face increased ESG- or anti-ESG-focused activism, its cost of capital may increase, and its reputation may also be negatively affected.  

The Corporation also makes certain disclosures regarding sustainability from time to time, including publishing an ESG report that provides updates on its performance related to certain ESG topics and discloses certain ESG goals. Many of the Corporation’s disclosures are necessarily based on estimates and assumptions that are inherently difficult to assess and 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. Mandatory ESG-related disclosure is also emerging as an area where the Corporation may be, or may become, subject to required disclosures in certain jurisdictions, and any such mandatory disclosures may similarly necessitate the use of hypothetical, projected or estimated data, some of which is not controlled by Enerplus and is inherently subject to imprecision. Disclosures reliant upon 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. 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, consequences 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 generally aspirational. Notwithstanding this, Enerplus may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals or policies,

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but it cannot guarantee it will be able to set or implement such goals or policies because of potential costs or technical or operational obstacles. In addition, the Corporation could be criticized by various anti-ESG stakeholders for the scope of Enerplus’ climate or ESG-related goals or policies, its strategic choices regarding ESG matters as they may impact its operations now or in the future, or for any revisions to the same, as well as initiatives that it may pursue or any public statements it may make. The Corporation could be subjected to negative responses by governmental actors (such as anti-ESG legislation or retaliatory legislative or administrative treatment) or consumers (such as boycotts or negative publicity campaigns), which could adversely affect its reputation, business, financial performance, market access and growth.

Furthermore, the Corporation’s reputation, as well as its stakeholder relationships, could be adversely impacted as a result of, among other things, any failure to meet its ESG plans or goals or stakeholder perceptions of statements made by Enerplus, its employees and executives, agents or other third parties, or public pressure from investors or policy groups to change its policies. Public statements with respect to ESG matters, including GHG 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. Both the SEC and the Canadian securities regulators have been monitoring issuers’ disclosures relating to various ESG-related matters and have published 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, including emissions reduction goals or standards used, were misleading, false, or otherwise deceptive. As a result, the Corporation may face increased litigation risks from private parties and governmental authorities related to it ESG efforts 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. To the extent that the Corporation is unable to respond timely and appropriately to any negative publicity, its reputation could be harmed. Damage to its overall reputation could have a negative impact on financial results and require additional resources to rebuild the Corporation’s reputation. In addition, to the extent alternative technologies are preferred, whether as a result of regulatory impacts, technological developments, or changes in industry practice, it may adversely impact Enerplus’ business or results of operation.

Government policy and/or regulations and required regulatory approvals and/or compliance with initiatives that target the oil and gas industry 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 and 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 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 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.

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Changes in laws or 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 and U.S. tax authorities having jurisdiction over the Corporation 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, 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 United States-Mexico-Canada Agreement, relating to trade among such countries, 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.

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.

In addition, the exchange ratio under the Arrangement is fixed and, other than in limited circumstances, will not be adjusted for changes in the market price of either of either Enerplus Common Shares or the shares of Chord common stock. Changes in the price of shares of Chord common stock prior to the completion of the Arrangement will affect the market value that Enerplus shareholders will be entitled to receive upon closing. Neither Enerplus nor Chord is permitted to terminate the Arrangement Agreement or resolicit the vote of the respective shareholders, solely because of changes in the market price of either corporation's shares.

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

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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 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.

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 dividends to shareholders. Enerplus has estimated the present value of its future asset retirement obligations to be $125.5 million at December 31, 2023 (see its Financial Statements) the majority of which are expected to be incurred between 2024 and 2033 for Canada, and 2036 and 2056 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 described elsewhere in this Annual Information Form, 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. See "Industry Conditions". The impact of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under 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 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.

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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 make certain climate change-related disclosure and/or significantly reduce GHG emissions, water consumption, or setback requirements for facilities and wells, could result in increased costs and competitive disadvantages. 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. 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 – 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; for instance, 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. 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 Canadian securities regulators 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 these rules and their requirements are not yet known, and the ultimate impact on the Corporation is uncertain, the proposed rules, if finalized, may result in increased compliance costs and increased costs of and restrictions on access to capital.

The Corporation may be subject to significant changes in government policy, resulting in reduced investment if it does not comply with expanded global climate change goals and targets, 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.

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 climate strategy, delivering a phased approach for key components. This strategy is designed to address climate change-related risks and opportunities for the Corporation. 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".

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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; harm to its ability to recruit or retain employees; 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

See “Supplemental Operational Information – Environmental, Social and Governance – Environment” for a discussion of the Corporation’s GHG emissions intensity initiatives. 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, the Corporation cannot guarantee that factors outside of its 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. Mandatory ESG-related disclosure is also emerging as an area where the Corporation may be, or may become, subject to required disclosures in certain jurisdictions, and any such mandatory disclosures may similarly necessitate the use of hypothetical, projected or estimated data, some of which is not controlled by Enerplus and is inherently subject to imprecision. Disclosures reliant upon 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. 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 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 set or 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.

Governments may pursue additional executive orders, new legislation and regulatory initiatives to further implement their regulatory agenda. The Corporation's operations in most jurisdictions require permits from one or more governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. In the United States, such permits are typically issued by state agencies, but U.S. federal and local governmental permits may also be required.

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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. 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 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, gathering 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 (as described below), resulting in operational delays, or even cancellation of construction of the required infrastructure or the shutdown of already operating infrastructure projects, any of which frustrate the Corporation’s ability to operate, produce and market its products. In addition, the assets of the Corporation are concentrated in regions with varying levels of government regulations, or under tribal or local rules that could result in the imposition of a limit or ban on shipping of commodities by truck, pipeline or rail.

OIL AND NATURAL GAS GATHERING SYSTEMS

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

The pace at which producer or midstream companies can construct adequate gathering infrastructure to capture the natural gas associated with the development of crude oil and NGLs properties may have an impact on the Corporation’s ability to increase crude oil production in its producing regions. Additionally, as exploration and drilling in these regions increases, the amount of natural gas being produced by the Corporation and others could exceed the capacity of the various gathering pipelines available in those areas. If these constraints remain unresolved, the Corporation's ability to transport its production to sales pipelines in these regions may be impaired and could adversely impact the Corporation's production volumes or realized prices in these areas. In the United States, the distinction between federally unregulated natural gas gathering facilities and FERC-regulated natural gas transmission pipelines under the Natural Gas Act 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

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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, which faces several ongoing legal challenges regarding an easement utilized on the pipeline route and the sufficiency of the environmental review process for the pipeline. The United States Army Corps of Engineers has previously stated that it considers the presence of the pipeline without an easement to constitute an encroachment on federal land but has not pursued an enforcement action with regards to this alleged encroachment. Although the Corporation's products may be delivered for transport to other pipelines, or by other means, any future 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.

The Corporation has the ability to transport its crude oil production by a diverse mix of pipeline, trucking and, if necessary, rail (after title is transferred to the buyer’s name), all of which are subject to various risks of cost escalation and/or new costs. In certain regions the Corporation is currently dependent upon only one means of transportation. With respect to rail transportation, there may be future incremental costs associated with transporting, and risks that access to rail transport may be constrained, depending upon changes made to existing rail transport regulations. More stringent government regulations concerning the usage of certain types of tank cars that transport crude oil and NGLs by rail in the United States 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 and 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.

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Higher than expected declines or curtailments in the Corporation’s production due to infrastructure constraints, third party operational business practices or failures, 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.

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.

Geopolitical risk and conflicts in or around major oil and gas producing nations can significantly impact commodity prices and, therefore the financial condition of the oil and gas industry.

Existing or future conflicts in major oil and gas producing nations and the international response may have potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Financial and trade sanctions that may be imposed against countries involved in such conflicts may have continued far-reaching effects on the global economy, energy and commodity prices. The short-, medium- and long-term implications of any such conflicts is difficult to predict with any degree of certainty. Depending on the extent, duration, and severity of such conflict(s), 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.

Dividends on, and the repurchases of, the Corporation's Common Shares are variable.

Although the Corporation currently intends to continue to return cash to shareholders with a quarterly dividend payment, investor returns may change from time to time due to changes in the amount of the cash dividend paid. Enerplus is restricted from repurchasing its shares under the Arrangement Agreement. 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

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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 can vary significantly from period to period for many reasons including, among other things:

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

The Corporation'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.

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The Corporation, through 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, cyberattack, cyber-fraud, cloud related threats and attacks on connected devices, business and email takeovers, security breach (including from a third party provider),  ransomware and destruction or interruption of the Corporation's information or operational technology systems by third parties (including software supply chain companies) 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”), operational technology (“OT”) 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. The Corporation's IT, OT and infrastructure, including process control systems, may be vulnerable to attacks by malicious persons or entities motivated by, among other things, geopolitical, financial or activist reasons, or may be breached due to employee error or malfeasance, or otherwise vulnerable due to other disruptions, including natural disasters and acts of war. Although the Corporation works to manage 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, OT and cyber risks have increased recently, including as a result of cybercriminals taking advantage of remote working environments to increase malicious activities, creating more threats for cyberattacks. These include phishing emails, malware-embedded mobile apps and targeting of vulnerabilities in remote access platforms.

In addition, as a general matter, the frequency and magnitude of cyberattacks is increasing and attackers have become more sophisticated. Cyberattacks are similarly evolving and include without limitation use of malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. The Corporation may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognizable until deployed. The Corporation may also be unable to investigate or remediate incidents as attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.

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 (eg. by monitoring/intercepting phones and communications, or surveilling/locating persons of interest) further increasing the risk of a breach of the Corporation’s security measures, which could result in a loss of material and confidential information and/or have a negative impact on the Corporation’s reputation, result in a breach of privacy laws, and/or disrupt business activities. In addition, third party operators on whom Enerplus  depends and the operations of its customers and business partners are also subject to such risks.

Any such attack, breach, access, disclosure or loss of information could also result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, remediation costs, disruptions to the Corporation's operations, decreased performance and production, an inability to settle transactions, misdirected wire transfers, reputational damage, increased costs, physical harm to people or the environment or other negative consequences.

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.

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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 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.

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

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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.

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”.

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.

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

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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'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.

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 United States, 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 United States are based on production and operators are required to maintain reclamation bonds for the wells and/or fields in which they operate. The Corporation also has certain abandonment and reclamation obligations in Alberta and British Columbia, which have recently implemented (or are in the process of implementing) more robust liability management regimes. Although the Corporation does not expect the current regimes or any changes to such programs to have a material impact on its abandonment program and the related costs thereof, Enerplus cannot guarantee the impact on its future abandonment and reclamation costs at this time.

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. Significant fluctuations in the Canada-U.S. foreign exchange rate may adversely impact the financial results of the Corporation.

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.

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, or otherwise in conflict with, 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.

ENERPLUS 2023 ANNUAL INFORMATION FORM    55

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.

56    ENERPLUS 2023 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 2023.

	TSX Trading			NYSE Trading
Month	High (CDN$)	Low (CDN$)	Volume	High (US$)	Low (US$)	Volume
January	24.20	21.34	11,910,986	18.17	15.77	6,166,117
February	23.75	20.78	13,631,397	17.79	15.34	5,942,162
March	22.98	17.65	25,156,076	16.70	12.84	10,623,398
April	20.93	19.41	11,797,693	15.61	14.24	6,159,810
May	20.45	18.63	9,399,609	15.12	13.73	6,684,949
June	20.28	18.23	8,849,664	15.13	13.73	8,474,418
July	22.36	18.43	8,440,749	16.98	13.80	5,131,348
August	23.37	21.56	10,444,633	17.32	16.15	5,867,607
September	24.32	22.27	11,876,972	18.00	16.52	6,050,787
October	24.72	22.04	11,277,257	18.05	16.05	6,131,248
November	24.74	21.27	10,090,603	18.09	15.47	6,037,735
December	21.83	19.31	10,439,565	16.19	14.25	7,747,367

ENERPLUS 2023 ANNUAL INFORMATION FORM    57

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.
Ian C. Dundas Calgary, Alberta, Canada	July 2013	President & Chief Executive Officer of Enerplus.
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. ​
M. Ward Polzin(2)(5) Denver, Colorado, United States	June 2023	Corporate director and founder and Executive Chairman at Camino Natural Resources, LLC, a private oil and gas company. Venture Partner of NGP Energy ("NGP"), a private equity investment firm.
Jeffrey W. Sheets(2)(4) Houston, Texas, United States	December 2017	Corporate director.
Sheldon B. Steeves(2)(3)(5) Calgary, Alberta, Canada	June 2012	Corporate director.

Notes:

1. Chair of the Board and ex officio member of all committees of the Board.

2. The Audit & Risk Management Committee is currently comprised of Jeffrey W. Sheets as Chair, Sherri A. Brillon, Judith D. Buie, Mark A. Houser, M. Ward Polzin and Sheldon B. Steeves.

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

4. The Compensation & Human Resources Committee is currently comprised of Mark A. Houser as Chair, Sherri A. Brillon, Karen E. Clarke-Whistler 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 M. Ward Polzin.  

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) (the "CCAA") 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.

58    ENERPLUS 2023 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.
Garth R. Doll Calgary, Alberta, Canada	Vice-President, Marketing & Midstream	Vice-President, 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.
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.

COMMON SHARE OWNERSHIP

As of February 20, 2024, the directors and officers of the Corporation named above beneficially own, or control or exercise direction over, directly or indirectly, an aggregate of 2,687,715 Common Shares, representing approximately 1.32% of the outstanding Common Shares as of that date.

CONFLICTS OF INTEREST

Certain of the directors and officers named above may be directors or officers of issuers 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".

ENERPLUS 2023 ANNUAL INFORMATION FORM    59

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, 2021 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.sedarplus.ca 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).

Copies of the following documents affecting the rights of securityholders have been filed on the Corporation's SEDAR+ profile at www.sedarplus.ca 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

60    ENERPLUS 2023 ANNUAL INFORMATION FORM

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. Equiniti Trust Company, LLC at its principal office in Newark, New Jersey 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.sedarplus.ca, 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 2024 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 2023 ANNUAL INFORMATION FORM    61

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, 2024. 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, 2024.

The following sections and tables summarize, as at December 31, 2023, 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, 2024, 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, 2024.

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 2023 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 COGE Handbook.  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, as at December 31, 2023, 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, 2023

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	43,871	35,239	4,510		3,635	538,973	432,562	138,210	110,967

Risked Net Present Value of Future Net Revenue

Contingent Resources (Forecast Prices and Costs)

As of December 31, 2023

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	2,264.8	1,086.4	566.4	314.7	183.3

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".

A-2    ENERPLUS 2023 ANNUAL INFORMATION FORM

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 61.5 MMBOE (53.9 MMBOE risked) of economic contingent resources to these formations, effective as of December 31, 2023, a decrease of 43% from the estimate as of December 31, 2022. The decrease compared to 2022 was primarily the result of 42.8 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 132.2 net future drilling locations over and above 389.6 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 $966.9 million between 2031 and 2034. 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 544.4 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 87.6% (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 $364.0 million. The Corporation has approximately 796 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 632.6 Bcf (506.1 Bcf risked) at December 31, 2023. The unrisked NPV (discounted at 10%) associated with these contingent resources is $253.1 million ($202.5 million risked). Approximately 11.3 Bcf of unrisked contingent resources were reclassified as reserves in 2023. An additional 7.0 Bcf of unrisked contingent resources (5.6 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 2023 reserves evaluations. This estimate represents a non-reserve land utilization rate of 91% and average well ultimate recovery of approximately 16.5 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 $349.6 million of capital will be required to develop these contingent resources with multifractured horizontal wells, and development will occur from 2028 to 2041.

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 2023 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, 2023. 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, 2023, 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, 2023.

    ENERPLUS 2023 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)
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
Purchases of reserves in place	-	-	-	-	-	-	-
Sales of reserves in place	(1,071)	(1,079)	-	-	(1,071)	(1,079)	(1,251)
Discoveries and extensions	32,854	40,173	-	-	32,854	40,173	39,549
Revisions of previous estimates	(14,230)	(168,461)	-	-	(14,230)	(168,461)	(42,307)
Improved recovery	-	-	-	-	-	-	-
Production	(22,702)	(82,775)	-	-	(22,702)	(82,775)	(36,498)
Proved Developed and Undeveloped
Reserves at December 31, 2023	170,904	665,325	-	-	170,904	665,325	281,792
Proved Developed Reserves
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
December 31, 2023	84,793	519,715	-	-	84,793	519,715	171,412
Proved Undeveloped Reserves
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
December 31, 2023	86,111	145,611	-	-	86,111	145,611	110,379

Purchases of reserves in place

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.

In 2023 the Corporation acquired no additional working interest reserve volumes through purchases.

B-2    ENERPLUS 2023 ANNUAL INFORMATION FORM

Sales of 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.

In 2023, the Corporation divested 1,071 Mbbls of net proved oil and NGLs reserves and 1,079 MMcf of natural gas reserves in North Dakota through farming out interests in three development units.

Discoveries and extensions

The Corporation added 73,683 Mbbls, 17,984 Mbbls and 32,463 Mbbls of net proved crude oil and NGLs reserves on its Bakken/Three Forks properties in 2021, 2022 and 2023, respectively. The Company added 271,393 MMcf, 109,250 MMcf and 13,974 MMcf of net proved natural gas reserves in 2021, 2022 and 2023, respectively, on its Marcellus natural gas property. These discoveries and extensions were primarily related to booking additional locations, as well as successful ell development.

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 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 2023, negative revisions to United States crude oil reserves were primarily due to revised development plans resulting in deletion of proved undeveloped wells, as well as a decrease in the crude oil Constant Price compared to 2022. Negative revisions to United States natural gas reserves were primarily due to a decrease in the natural gas Constant Price compared to 2022, which caused economic truncations of producing volumes and the removal of no longer economic undeveloped locations, as well as revised development plans and deletion of proved undeveloped locations in the Marcellus natural gas property.

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 2021, 2022 and 2023.

    ENERPLUS 2023 ANNUAL INFORMATION FORM    B-3

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

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

	2023		2022		2021
	(in US$ thousands)
Capitalized costs(1)	$	7,758,278	$	7,214,993	$	13,075,987
Less accumulated depletion, depreciation and impairment		(6,246,596)		(5,892,089)		(11,822,482)
Net capitalized costs	$	1,511,682	$	1,322,904	$	1,253,505

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, 2023
	United States		Canada		Total
	(in US$ thousands)
Acquisition of properties:
Proved	$	7,342	$	`	$	7,342
Unproved		-		-		-
Exploration costs		1,826		-		1,826
Development costs		535,929		-		535,929
	$	545,097	$	-	$	545,097

	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

B-4    ENERPLUS 2023 ANNUAL INFORMATION FORM

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

The Corporation’s crude oil and natural gas producing activities represent substantially all of its business activities, which were also located substantially in the U.S. for the years ended December 31, 2023, 2022 and 2021. Refer to the Financial Statements for additional information on the Corporation’s results of operations for oil and gas producing activities.

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, 2023
	United States			Canada		Total
	(in $US millions)
Future cash inflows	$	10,888	$	-	$	10,888
Future production costs		3,824		-		3,824
Future development and asset retirement costs		1,804		-		1,804
Future income tax expenses		1,079		-		1,079
Future net cash flows	$	4,181	$	-	$	4,181
Deduction: 10% annual discount factor		1,309		-		1,309
Standardized measure of discounted future net cash flows	$	2,873	$	-	$	2,873

	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

    ENERPLUS 2023 ANNUAL INFORMATION FORM    B-5

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

	2023		2022		2021
	(in $US millions)
Beginning of year	$	5,529	$	3,413	$	368
Sales of oil and natural gas produced, net of production costs		(993)		(1,666)		(960)
Net changes in sales prices and production costs		(4,590)		4,845		2,347
Changes in previously estimated development costs incurred during the period		531		410		302
Changes in estimated future development costs		(505)		(548)		(1,278)
Extension, discoveries and improved recovery, net of related costs		879		981		2,285
Purchase of reserves in place		-		1		1,214
Sales of reserves in place		(25)		(229)		(12)
Net change resulting from revisions in previous quantity estimates		648		(1,062)		(251)
Accretion of discount		588		300		26
Net change in income taxes		809		(917)		(630)
Other significant factors (Exchange rate)		-		-		3
End of year	$	2,873	$	5,529	$	3,413

ADDITIONAL RESERVES INFORMATION

The following tables set forth a summary of the Corporation’s total proved reserves based on volumes that are calculated in accordance with 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, as well as Future Development Costs to develop those reserves. These disclosures are not part of the disclosures required by U.S. Rules.

I. NET RESERVES PROVED RESERVES SUMMARY

	Tight Oil (Mbbls)	Total Crude Oil (Mbbls)	Natural Gas Liquids (Mbbls)	Shale Gas (MMcf)	Total Natural Gas (MMcf)	Total (MBOE)
Net
Proved developed producing	68,884	68,884	14,934	511,573	511,573	169,080
Proved developed non-producing	871	871	104	8,142	8,142	2,332
Proved undeveloped	73,360	73,360	12,751	145,611	145,611	110,379
Total Proved	143,115	143,115	27,789	665,235	665,235	281,792

II. NET PROVED RESERVES RECONCILIATION

7
	Tight Oil (Mbbls)	Total Crude Oil (Mbbls)	Natural Gas Liquids (Mbbls)	Shale Gas (MMcf)	Total Natural Gas (MMcf)	Total (MBOE)
Proved Reserves at Dec. 31, 2022	148,953	148,953	27,100	877,468	877,468	322,298
Purchases of reserves in place	-	-	-	-	-	-
Sales of reserves in place	(952)	(952)	(119)	(1,079)	(1,079)	(1,251)
Discoveries and extensions	28,551	28,551	4,303	40,173	40,173	39,549
Revisions of previous estimates	(14,905)	(14,905)	675	(168,462)	(168,462)	(42,307)
Improved recovery	-	-	-	-	-	-
Production	(18,532)	(18,532)	(4,170)	(82,775)	(82,775)	(36,498)
Proved Reserves at Dec. 31, 2023	143,115	143,115	27,789	665,325	665,325	281,792

B-6    ENERPLUS 2023 ANNUAL INFORMATION FORM

III. 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)
2024	405
2025	466
2026	408
2027	283
2028	-
2029	-
Remainder	-
Total FDC Undiscounted	1,562
Total FDC Discounted at 10%	1,321

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

    ENERPLUS 2023 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, 2023. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, 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, 2023, 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, 2023, 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, 2023	North Dakota & Colorado, USA	-	$	5,269,040.4	$	-	$	5,269,040.4
Netherland, Sewell & Associates, Inc.	December 31, 2023	Pennsylvania, USA	-	$	655,589.0	$	-	$	655,589.0
TOTALS				$	5,924,629.4	$	-	$	5,924,629.4

● 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 2023 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, 2023	North Dakota, USA	53.9	$	-	$	363,966.6	$		363,966.6
Development Pending Contingent Resources (2C)	Netherland, Sewell & Associates, Inc.	December 31, 2023	Pennsylvania, USA	84.4	$	-	$	202,473.7	$		202,473.7

● 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 21, 2024	February 21, 2024

C-2    ENERPLUS 2023 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 21, 2024

   ENERPLUS 2023 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, Ward Polzin 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 ("ConocoPhillips") 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.

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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 ("RPM"), 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.
M. Ward Polzin (B. S. (Petroleum Engineering), MBA, CFA (Director since June 2023)	Mr. Polzin is a Venture Partner of NGP Energy ("NGP"), a private equity investment firm based in Dallas, TX, and brings with him over 35 years of leadership, engineering, commercial, financial, and investing experience in the energy industry. Mr. Polzin is the founder and Executive Chairman of Camino Natural Resources, LLC, an NGP portfolio oil and gas company started in 2017. Mr. Polzin also serves on the Board of Directors of Cygnet Energy Ltd., another NGP portfolio company. He received a Bachelor of Science in Petroleum Engineering at the Colorado School of Mines and an MBA from Rice University. He is also a CFA charterholder.

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Name (Director Since)		Principal Occupation and Biography
Sheldon B. Steeves (B. Sc. (Geology) (Director since June 2012) Other Public Directorships ·     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 2023 and 2022 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. 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:

		2023		2022
		(in US$ thousands)
Audit fees(1)	$	974.9	$	835.9
Audit-related fees(2)		-		-
Tax fees(3)		165.5		377.1
All other fees(4)		-		-
TOTAL	$	1,140.4	$	1,213.0

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”.

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AUDIT & RISK MANAGEMENT COMMITTEE CHARTER

I.         AUTHORITY

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

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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

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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.

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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.

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Enerplus Corporation

The Dome TowerU.S. 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

Email: investorrelations@enerplus.comFax: 720-279-5550

www.enerplus.com