Associates Consultants Ltd., an independent petroleum consulting firm, ("McDaniel"), and 84 gross (60.9 net) unbooked future drilling locations not associated with any reserves of Bruin identified by internal qualified reserves evaluators). Bruin's properties are all located in North Dakota, with most of its interests being in the Fort Berthold area near Enerplus' primary property. See "Description of Bruin's Assets and Operations" in this material change report.

The Purchase Agreement

The following is a summary of the material terms of the Purchase Agreement.

The Purchase Agreement provides for the acquisition by Enerplus USA of all of the equity interests of Bruin for the Purchase Price, payable in cash. The Purchase Price is subject to certain adjustments including, among other things, for title and environmental defects and for certain operating items between the January 1, 2021 effective date of the Acquisition and the closing date of the Acquisition (the "Acquisition Closing Date"). Enerplus USA will generally be entitled to receive all revenues and benefits arising from Bruin's assets, and shall be responsible for all obligations and expenditures in respect of Bruin's assets, on and after the effective date of January 1, 2021. An interim estimate of all adjustments required pursuant to the Purchase Agreement will be carried out by the Vendor on the Acquisition Closing Date and a final settlement statement will be prepared by Enerplus USA within 90 days of the Acquisition Closing Date.

The Purchase Agreement contains a covenant in favour of Enerplus USA that allows Enerplus USA to conduct due diligence prior to the Acquisition Closing Date, including an on-site visual inspection of Bruin's properties and an ASTM Phase I environmental review thereof. Title and environmental defects that individually exceed a minimum threshold and in the aggregate (net of any title benefit amounts) exceed 2.5% of the Purchase Price, shall result in a downward adjustment to the Purchase Price of the amount such defects and losses exceed the 2.5% deductible. If the amount of title and environmental defects (subject to a minimum threshold and aggregate deductible) and casualty losses resulting in a downward adjustment to the Purchase Price are in excess of 10% of the Purchase Price, then either Enerplus USA or the Vendor may terminate the Purchase Agreement.

The Purchase Agreement also includes customary conditions to closing of the Acquisition including, but not limited to, the following: (a) the accuracy of each party's representations and warranties and the performance of their respective covenants in all material respects; and (b) no actions or orders that prohibit the consummation of the Acquisition have been issued and remain in force. In addition, the Purchase Agreement may be terminated by either party if the Acquisition Closing Date has not occurred by March 10, 2021, and automatically terminates if the Acquisition Closing Date has not occurred by April 15, 2021.

Enerplus USA is obligated to provide a deposit in escrow in the amount of US$23.25 million in support of its obligations pursuant to the Purchase Agreement (the "Deposit"). If the Acquisition is completed, the Deposit will be credited to the Purchase Price. If the Acquisition does not close due to a material breach by Enerplus USA of its representations, warranties or covenants, the Deposit shall be forfeited to the Vendor, which forfeiture will be the exclusive remedy of the Vendor in that circumstance. If closing of the Acquisition does not occur due to the Vendor's default, or the parties agree to terminate the Purchase Agreement for any other reason, the Vendor will return the Deposit to Enerplus USA. In the event that the conditions precedent to Vendor's obligations have been satisfied or waived (or would have been satisfied except for the breach of Vendor) and the closing of the Acquisition has not occurred as a result of Vendor's material breach, Enerplus USA may elect to either exercise any and all rights and remedies at law or in equity, including specific performance, or terminate the Purchase Agreement and receive its Deposit.

The Purchase Agreement contains customary representations and warranties from Enerplus USA and the Vendor for a transaction of this nature, including by the Vendor in respect of the corporate organization

and share ownership of Bruin and its subsidiaries, ownership of the assets of Bruin and its subsidiaries, environmental matters, compliance with laws, financial statements, liabilities and taxes.

Prior to the completion of the Acquisition, the Vendor has agreed to maintain and operate Bruin's business in accordance with the terms set forth in the Purchase Agreement, which includes operating it in the ordinary course of business consistent with past practice. The Vendor has also agreed to cause Bruin not to undertake certain activities with respect to its business and assets without Enerplus USA's prior written consent (not to be unreasonably withheld, conditioned or delayed).

Enerplus USA and the Vendor have agreed to indemnify each other for a period of twelve months from the Acquisition Closing Date in respect of certain losses and liabilities arising out of breaches of representations and warranties or a failure to perform covenants, subject to certain exceptions that have longer survival periods. In addition, the Vendor has agreed to indemnify Enerplus USA for certain other matters not specifically captured by its representations and warranties relating to Bruin employee and tax matters, excluded assets and pre-closing liabilities, and Enerplus USA has agreed to indemnify the Vendor and certain of its related parties after closing from and against any liabilities arising out of the ownership and operation of Bruin's assets or the ownership of Bruin (whether before or after the Acquisition Closing Date) and for all environmental liabilities of Bruin or pertaining to its assets, unless relating to a matter for which the Vendor has agreed to indemnify Enerplus USA. These indemnities are subject to certain limited exceptions, minimum thresholds and maximum amounts, in a manner which is customary for agreements of this type. Subject to certain limited exceptions, neither party will be liable for any loss of profits, other consequential, special or punitive damages in connecting with the Purchase Agreement or the Acquisition.

Financing of the Acquisition and Term Facility

Enerplus expects to finance the Purchase Price with a portion of the net proceeds of the Prospectus Offering, as well as by drawing the full amount of US$400 million available under the Term Facility. On January 25, 2021, Enerplus entered into a binding commitment letter dated January 25, 2021 pursuant to which Royal Bank of Canada and Bank of Montreal have committed, subject to the terms and conditions set forth therein, to make the Term Facility available to the Corporation (the "Commitment Letter") to be fully drawn down on the Acquisition Closing Date to pay for the remaining portion of the Purchase Price. The Term Facility will include financial and other covenants substantially identical to those under the existing Credit Facility, as well as similar pricing to the Credit Facility. The Commitment Letter contains limited conditions to funding, including completion of the Acquisition substantially on the terms set forth in the Purchase Agreement and delivery of customary credit facility documentation. If the Acquisition is not completed, Enerplus will not enter into the Term Facility and will not have access to the US$400 million of funds available thereunder.

Description of Bruin's Assets and Operations

Description of Bruin's Properties

Outlined below is a description of Bruin's crude oil and natural gas properties and assets, all of which are located in North Dakota. Bruin's primary U.S. crude oil properties are located in the Fort Berthold, Williams and Russian Creek regions of North Dakota.

Bruin has approximately 29,927 net acres of land in Fort Berthold, primarily in Dunn and McKenzie Counties and, on a production basis, operates approximately 99% of its Fort Berthold assets. The Corporation's Fort Berthold property produces a light sweet crude oil with some associated natural gas and NGLs, from both the Bakken and Three Forks formations. Fort Berthold production averaged approximately 23,386 BOE/day in 2020 consisting of approximately 16,027 bbls/day of tight oil,

approximately 3,649 bbls/day of NGLs and approximately 22,259 Mcf/day of conventional natural gas. In the Fort Berthold region 3.8 net wells were brought on-stream from a pad that was drilled in 2019. In addition, Bruin has an operated working interest in 4.5 net wells that it drilled in 2020 targeting the Bakken and Three Forks formations which remain yet to be completed. Enerplus expects these 4.5 net drilled uncompleted wells to be completed and brought on production in 2021.

Bruin also has working interests in the Williams and Russian Creek areas, which produced an average of approximately 4,794 BOE/day from the Bakken formation in 2020, consisting of approximately 3,975 bbls/day of light and medium crude oil, approximately 492 bbls/day of NGLs and approximately 1,962 Mcf/day of conventional natural gas. Through 2020, Bruin drilled 5.4 net horizontal wells in the Williams region, targeting the Middle Bakken formation (all of which were long lateral wells). Enerplus expects these 5.4 net drilled uncompleted wells to be completed and brought on stream in 2021.

Overall, Bruin's U.S. crude oil properties produced an average of approximately 28,180 BOE/day in 2020. Total proved plus probable reserves associated with Bruin's properties as at December 31, 2020 were 84.1 MMBOE, as described in more detail below under " – Summary of Oil and Gas Reserves".

In 2020, Bruin incurred capital expenditures (essentially all of which were development costs and not exploration costs) of approximately US$40 million on its properties. The Corporation anticipates that increased spending by the Corporation on these properties in 2021 following completion of the Acquisition will be in the range of US$40 million to US$55 million.

Quarterly Production History

The following table sets forth Bruin's average daily gross production volumes by product type, for each fiscal quarter in 2020 and for the entire year. Production decreased significantly after the first quarter of 2020 due to commodity price-related oil production curtailments and the elimination of almost all development capital spending on the properties.

	Year Ended December 31, 2020
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Annual
Product Type
Tight oil (bbls/day)	28,951	15,496	17,707	17,902	20,002
Natural gas liquids (bbls/day)	6,397	3,724	3,515	2,949	4,141
Total liquids (bbls/day)	35,348	19,220	21,222	20,851	24,143
Shale gas (Mcf/day)	39,050	20,503	20,059	17,395	24,222
Total (BOE/day)	41,856	22,637	24,565	23,750	28,180

Exploration and Development Activities

In 2020, Bruin drilled or participated in the drilling of six gross (5.4) net crude oil wells.

Oil and Natural Gas Wells and Unproved Properties

Based on information available to it, Enerplus estimates that Bruin has interests in approximately 345 gross (275 net) producing oil wells and approximately 110 gross (85 net) non-producing oil wells which were not producing but may be capable of production.

Enerplus does not believe that a material portion of Bruin's unproved properties are scheduled to expire in the near term, or would require material expenditures to be made or work conducted in the near term to preserve the rights associated with those properties.

Summary of Oil and Gas Reserves

All of Bruin's reserves have been independently evaluated for the Corporation in accordance with NI 51-101 by McDaniel, with an effective date of December 31, 2020. McDaniel used the average of the commodity price forecasts and inflation rates of GLJ Petroleum Consultants ("GLJ"), McDaniel and Sproule Associates Limited ("Sproule") as of January 1, 2021 to prepare its report.

The following sections and tables summarize, as at December 31, 2020, Bruin'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 evaluation and, as a result, the tables may contain slightly different numbers than the evaluation due to rounding. Additionally, the columns and rows in the tables may not add due to rounding.

All estimates of future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures, and are presented before deducting income taxes, as Bruin is a non-taxable U.S. entity. 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 Bruin'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 Financial and Oil and Gas Information" in this material change report 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 Bruin's reserves at December 31, 2020, using forecast price and cost cases.

Summary of Oil and Gas Reserves (Forecast Prices and Costs)
As of December 31, 2020

	OIL AND NATURAL GAS RESERVES
RESERVES	Tight Oil			Natural Gas Liquids			Shale Gas		Total
CATEGORY	Gross	Net	Gross		Net	Gross		Net		Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)		(Mbbls)	(MMcf)		(MMcf)		(MBOE)	(MBOE)
Proved Developed Producing	24,648	20,084	4,536		3,698	26,515		21,607		33,604	27,383
Proved Developed Non-Producing	5,352	4,350	1,390		1,133	8,324		6,780		8,129	6,613
Proved Undeveloped	14,410	11,777	2,387		1,951	13,389		10,936		19,029	15,551
Total Proved	44,410	36,211	8,313		6,782	48,228		39,323		60,761	49,547
Probable	17,043	13,900	3,309		2,701	18,156		14,803		23,378	19,068
Total Proved Plus Probable	61,453	50,110	11,622		9,483	66,385		54,125		84,139	68,615

Notes:

(1)	Gross reserves are working interest reserves before royalty deductions.

(2)	Net reserves are working interest reserves after royalty deductions plus royalty interest

(3)	Natural Gas Liquids include Condensate volumes.

Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves (Forecast Prices and Costs)
As of December 31, 2020

	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED BT (%/Year)
	Before Deducting Income Taxes					Unit
RESERVES CATEGORY	0%	5%	10%	15%	20%	Value⁽¹⁾
	(in $ millions)					$/BOE
Proved Developed Producing	491	445	400	361	329	$14.61
Proved Developed Non-Producing	99	90	81	73	66	$12.30
Proved Undeveloped	199	147	108	79	58	$6.93
Total Proved	790	683	589	513	453	$11.89
Probable	450	322	238	182	144	$12.47
Total Proved Plus Probable	1,239	1,005	827	695	596	$12.05

Note:

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

Forecast Prices and Costs

The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021, and the following inflation and exchange rate assumptions:

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

Notes:

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

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

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

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

(5)	Escalation is approximately 2% per year thereafter.

Undiscounted Future Net Revenue by Resources Category

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

RESERVES CATEGORY	Revenue	Royalties⁽¹⁾	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(in $ millions)
Proved Reserves	3,188	834	1,143	293	128	790

Proved Plus Probable Reserves	4,558	1,192	1,570	416	141	1,239

Notes:

(1)	Includes all product revenues and other revenues as forecast.

(2)	Royalties include any net profits interests paid.

Net Present Value of Future Net Revenue by Reserves Category and Product Type

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

		Future Net Revenue Before Income Taxes
RESERVES CATEGORY	PRODUCT TYPE	(Discounted at 10%)	Unit Value⁽¹⁾
		(in $ thousands)	($/bbl; $/Mcf)
Proved Reserves	Tight Oil⁽²⁾	589,171	16.27
	Shale Gas⁽⁴⁾	n/a	n/a
	Total	589,171
Proved Plus Probable Reserves	Tight Oil⁽²⁾	826,866	16.50
	Shale Gas⁽⁴⁾	n/a	n/a
	Total	826,866

Notes:

(1)	Unit values are calculated using the 10% discounted rate divided by the major product type net reserves for each group, which is only comprised of tight oil.

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

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

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

Estimated Production for Gross Reserves Estimates

The volume of total production for Bruin estimated for 2021 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual 2021 production may vary from the estimates below as the actual development programs, timing and priorities on Bruin's properties and assets conducted by the Corporation following closing of the Acquisition may differ from the forecast of development. Columns may not add due to rounding.

	Gross Proved Reserves		Gross Probable Reserves		Gross Proved + Probable Reserves
Product Type	Estimated 2021 Aggregate Production	Estimated 2021 Average Daily Production	Estimated 2021 Aggregate Production	Estimated 2021 Average Daily Production	Estimated 2021 Aggregate Production	Estimated 2021 Aggregate Production
Tight Oil	6,787 Mbbls	18,595 bbls/day	314 Mbbls	860 bbls/day	7,101 Mbbls	19,455 bbls/day
Natural Gas Liquids	1,303 Mbbls	3,568 bbls/day	64 Mbbls	174 bbls/day	1,366 Mbbls	3,743 bbls/day
Total Liquids	8,090 Mbbls	22,163 bbls/day	378 Mbbls	1,035 bbls/day	8,467 Mbbls	23,198 bbls/day
Shale Gas	7,493 MMcf	20,530 Mcf/day	353 MMcf	967 Mcf/day	7,846 MMcf	21,497 Mcf/day
Total	9,339 MBOE	25,585 BOE/day	436 MBOE	1,196 BOE/day	9,775 MBOE	26,781 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.

	Proved Reserves		Proved Plus Probable Reserves
Year	Undiscounted (M$)	Discounted at 10%/year (M$)	Undiscounted (M$)	Discounted at 10%/year (M$)

2021	55,808	53,218	55,808	53,218
2022	80,153	68,963	80,153	68,963
2023	120,716	94,565	120,716	94,565
2024	35,926	26,702	141,916	102,069
2025	-	-	17,224	11,660
2026	-	-	-	-
Remainder	-	-	-	-
Total	292,602	243,448	415,817	330,474

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 Bruin'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 Bruin's reserves data.

In connection with its operations, the Corporation will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines, including on Bruin's properties. The Corporation budgets for and recognizes as a liability the estimated present value of the future decommissioning liabilities associated with its property, plant and equipment. There are no unusually significant abandonment and reclamation costs associated with Bruin's reserves properties or properties with no attributed reserves, and the Corporation does not anticipate its abandonment and reclamation liabilities to negatively impact Bruin's reserves data or its ability to develop these reserves at this time.

Proved and Probable Reserves Not on Production

Bruin has approximately 10.1 MMBOE of proved plus probable reserves which are capable of production but which, as of December 31, 2020, were not on production. These reserves have generally been non-producing for periods ranging from a few months to just under two years. The majority of these volumes are associated with operated wells that are shut-in due to pump failures. All of these non-producing assets have been scheduled to recommence production by 2022.

Marketing Arrangement and Forward Contracts

Bruin's crude oil production is marketed to various buyers using a mix of negotiated contracts that are in place over various lengths of time. Bruin transports its U.S. crude oil production to its buyers by pipeline and/or truck. Bruin may also at times transport a portion of its North Dakota crude oil production to the

U.S. Gulf Coast, where it can further access export crude oil markets. Bruin's NGLs associated with its crude oil production volumes are marketed on its behalf by midstream companies in North Dakota.

All of Bruin's natural gas production was associated natural gas production from its crude oil operations in North Dakota. Bruin does not market these volumes directly, as they are marketed on Bruin's behalf by midstream companies in North Dakota.

Bruin uses various types of derivative financial instruments to manage the risk related to fluctuating commodity prices. Absent such hedging activities, all of the crude oil of Bruin is sold into the open market at prevailing market prices, which exposes Bruin to the risks associated with commodity price fluctuations. As of January 25, 2021, Bruin has WTI financial swaps in place for an average of approximately 9,045 bbls/day of crude oil production for February through December 2021 at an average price of US$42.36/bbl.

Risks Related to the Acquisition and the Corporation

Possible Failure or Delay in the Acquisition

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

Unexpected Costs or Liabilities Related to the Acquisition

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

In connection with the Acquisition, there may be liabilities that the Corporation failed to discover or was unable to quantify in the Corporation's due diligence which the Corporation will conduct up to the Acquisition Closing Date and the Corporation may not be indemnified for some or all of these liabilities. The discovery or quantification of any material liabilities could have a material adverse effect on the Corporation's business, financial condition or future prospects. In addition, the Purchase Agreement limits the amount for which the Corporation is indemnified, such that liabilities in respect of the Acquisition may be greater than the amounts for which the Corporation is indemnified under the Purchase Agreement. See "The Acquisition – the Purchase Agreement" in this material change report.

Realization of Acquisition Benefits

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

Increased Level of Debt

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

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

U.S. Administration

The recent changes in control of the U.S. Congress and the election of President Biden may result in legislative and regulatory changes that could have an adverse effect on the Corporation. In particular, President Biden has indicated that his administration will seek to curtail hydraulic fracturing on federal lands, possibly through delays or bans on the issuance of drilling permits, and his administration may pursue other regulatory initiatives, executive actions and legislation in support of his regulatory agenda. The Corporation's operations in most jurisdictions require permits from one or more governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. In the United States, such permits are typically issued by state agencies, but U.S. federal and local governmental permits may also be required. In addition, some of the Corporation's drilling and completion activities in the United States may take place on U.S. federal land or Native American lands, requiring leases and other approvals from the U.S. federal government or Native American tribes to conduct such drilling and completion activities. Under certain circumstances, U.S. federal agencies may refuse to approve new leases for hydrocarbon exploration and development on federal lands, and may refuse to grant or delay approvals required for development of existing leases. On January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that effectively suspends new oil and gas leases and drilling permits on federal lands and waters for a period of 60 days. The suspension does not limit existing operations under valid leases. On January 25, 2021 the U.S. Department of the Interior clarified this order to indicate that it does not apply to Native American lands. President Biden has previously announced plans to ban new leases for oil and gas development on federal lands and recent news reports indicate this action may be imminent. 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. In addition, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Climate Agreement, which could result in additional U.S. executive orders or U.S. federal legislation or regulatory initiatives in a purported effort to achieve the agreement's goals.

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

Enerplus operations in the Williston Basin may be adversely affected by a shutdown of the Dakota Access Pipeline

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

5.2	Disclosure for Restructuring Transactions

Not applicable.

6.	Reliance on Subsection 7.1(2) of National Instrument 51-102

Not applicable.

7.	Omitted Information

Not applicable.

8.	Executive Officer

The name and business telephone number of an executive officer of the Corporation who is knowledgeable about the material change and this material change report is:

Jodi Jenson Labrie, Senior Vice-President & Chief Financial Officer

Tel: (403) 298-2200

9.	Date of Report

January 29, 2021.

All amounts in this material change report are stated in Canadian dollars unless otherwise specified.

Forward-Looking Information and Statements

This material change report contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "ongoing", "may", "will", "project", "plans", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this material change report contains forward-looking information pertaining to the following: anticipated completion of the Acquisition and financings, including expected size, terms, timing and completion thereof; and expected benefits of the Acquisition.

The forward-looking information contained in this material change report reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that the Acquisition will be completed substantially on the terms and within the timeline described in this material change report; and that Enerplus will realize the expected benefits of the Acquisition described in this material change report. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations, and assumptions will prove to be correct. The forward-looking information included in this material change report is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: failure to complete the Acquisition, at all or on terms or within the timeline described in this material change report; failure by Enerplus to realize anticipated benefits of the Acquisition; and other risks set forth in this material change report and other risks detailed from time to time in the Corporation's public disclosure documents.

Presentation of Information in this Material Change Report

Information about Bruin

As the Corporation does not currently own Bruin (as defined herein), the information in this material change report relating to Bruin and its properties and business, has been summarized from information obtained from the Vendor and its affiliates. None of Bruin, the Vendor or any of their respective affiliates or their respective directors, officers, employees, shareholders, members, partners, agents or other representatives (each a "Bruin Party") makes any representation or warranty as to the accuracy or completeness of the information regarding Bruin or the Vendor contained in this material change report, and no Bruin Party was involved in the preparation or assembly of this material change report. No Bruin Party assumes any responsibility or liability for any errors or omissions in, or for any damages resulting from the use of, or any reliance on, any part of the information contained in this material change report.

The McDaniel reserves report on the Bruin properties effective December 31, 2020 was prepared on behalf of the Corporation with information provided by the Corporation and other industry information available to McDaniel, and no Bruin Party participated in or provided any information to McDaniel in respect of such report. The oil and gas

production volumes for Bruin that were made available to the Corporation were determined on a net basis, consistent with U.S. disclosure requirements and industry practice, and the Corporation has estimated gross production volumes, in accordance with NI 51-101, based on royalty and other information available to it.

General

Unless otherwise stated, all of the reserves information contained in this material change report has been prepared and presented in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, adopted by the Canadian securities regulatory authorities, and the reserves definitions contained in the Canadian Securities Administrators Staff Notice 51-324. Unless otherwise stated, all of the reserves and production information in this material change report is on "gross" basis, which are Enerplus' working interest share before deduction of royalties and without including any royalty interests of the Corporation. The oil and gas production volumes for Bruin that were made available to Enerplus were determined on a net basis, consistent with U.S. disclosure requirements and industry practice, and the Corporation has estimated gross production volumes, in accordance with NI 51-101, based on royalty and other information available to it.

The Corporation's actual oil and natural gas reserves and future production, including following completion of the Acquisition, may be greater than or less than the estimates provided in this material change report. 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.

Barrels of Oil Equivalent

The Corporation has adopted the standard of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to barrels of oil equivalent. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does 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 six to one, utilizing a conversion on a six to one basis may be misleading as an indication of value.

Abbreviations

In this material change report, 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
BOE	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
WTI	West Texas Intermediate
NYMEX	New York Mercantile Exchange


BY:	/s/	David A. McCoy
		David A. McCoy
		Vice President, General Counsel & Corporate Secretary

DATE: February 9, 2021