Form 6-K ENERPLUS Corp For: Apr 19

April 19, 2021 12:39 PM EDT

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FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Report of Foreign Issuer pursuant to Rule 13-a-16 or 15d-16

of the Securities Exchange Act of 1934

 

FOR THE MONTH OF APRIL, 2021

 


 

COMMISSION FILE NUMBER  1-15150

 

Graphic

The Dome Tower

Suite 3000, 333 – 7th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

 

(403) 298-2200

 


Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F Form 40-F X

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)

Yes No X

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)

Yes No X

The exhibits to this report shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statements under the Securities Act of 1933 on Form F-10 (File No. 333-231548) and Form S-8 (File Nos. 333-200583 and 333-171836).



 


EXHIBIT INDEX

EXHIBIT 99.1 – Enerplus – Material Change Report


SIGNATURE


 

    Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

ENERPLUS CORPORATION

 

25

BY:

/s/

Jodine J. Jenson Labrie

 

 


Jodine J. Jenson Labrie

 

 

Senior Vice President and Chief Financial Officer

 

 

 

DATE: April 19, 2021


Exhibit 99.1

FORM 51-102F3
MATERIAL CHANGE REPORT

Name and Address of Company

Enerplus Corporation ("Enerplus" or the "Corporation")

3000, 333 - 7th Avenue S.W.

Calgary, Alberta  T2P 2Z1

Date of Material Change

April 7, 2021

News Release

A news release relating to the material changes described herein was disseminated through the facilities of Cision and subsequently filed on SEDAR.

Summary of Material Change

On April 8, 2021, Enerplus announced that its indirect wholly-owned subsidiary, Enerplus Resources (USA) Corporation ("Enerplus USA"), has entered into a purchase and sale agreement (the "Purchase Agreement") with Hess Bakken Investments II, LLC (the "Vendor") to acquire certain crude oil and natural gas assets of the Vendor comprised of 78,700 net acres in the Williston Basin and associated reserves, production and infrastructure (the "Acquired Assets") for total consideration of US$312 million (the "Purchase Price"), payable in cash, subject to certain customary adjustments (the "Acquisition"). Closing of the Acquisition is subject to customary closing conditions and is expected to occur in May 2021.

The Acquisition will be funded with the Corporation's existing cash position of approximately US$150 million, with the remaining portion of the Purchase Price funded through borrowing on the Corporation's undrawn US$600 million senior unsecured covenant-based credit facility with a syndicate of financial institutions maturing on October 31, 2023.

5.1Full Description of Material Change

The Acquisition

Overview

On April 7, 2021, Enerplus USA, an indirect wholly-owned subsidiary of Enerplus, entered into the Purchase Agreement to acquire the Acquired Assets for the Purchase Price, payable in cash, subject to certain customary adjustments. Closing of the Acquisition is subject to customary closing conditions and is expected to occur in May 2021.

Pursuant to the Acquisition, the Corporation will acquire 78,700 largely contiguous net acres in Dunn County, North Dakota. The Acquisition includes approximately 6,000 BOE/day (76% tight oil, 10% NGLs and 14% shale gas) of production, with a base decline rate under 20% (10% on the operated production, 37% on the non-operated production). The McDaniel Report (as defined below) has assigned 62.7 MMBOE of proved plus probable reserves to the Acquired Assets, consisting of 49.7 MMbbls of tight oil, 7.1 MMbbls of NGLs and 35.1 Bcf of shale gas. The Acquisition also includes an inventory of 153 gross


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(66.1 net) proved plus probable undeveloped reserves locations identified by McDaniel & Associates Consultants Ltd., an independent petroleum consulting firm, ("McDaniel"), 166 gross (44.5 net) unbooked potential future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators and considered economic, and 155 gross (120.7 net) unbooked potential future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators as offering future development potential but with marginal economics based on the current assessment. The Acquired Assets are all located in North Dakota, with most of its interests being in the Little Knife, Murphy Creek and Russian Creek areas. See "Description of the Acquired Assets" 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 the Acquired Assets for the Purchase Price, payable in cash on the closing date of the Acquisition, currently anticipated to be on or about May 18, 2021 (the "Acquisition Closing Date"). The Purchase Price is subject to certain customary adjustments including, among other things, for certain title and environmental defects and for certain operating costs and expenses between the March 1, 2021 effective date of the Acquisition and the Acquisition Closing Date. Subject to certain customary exceptions, Enerplus USA will generally be entitled to receive all revenues and benefits arising from the Acquired Assets, and will be responsible for all obligations and expenditures in respect of the Acquired Assets, from and after the effective date of the Acquisition. An interim estimate of all adjustments required pursuant to the Purchase Agreement will be prepared by the Vendor on the Acquisition Closing Date, and a final settlement statement will be prepared by the Vendor within 90 days of the Acquisition Closing Date, which will be subject to final approval by Enerplus USA.

The Purchase Agreement contains a covenant in favour of Enerplus USA that allows Enerplus USA to conduct due diligence on the Acquired Assets prior to the Acquisition Closing Date, including providing Enerplus USA with reasonable access to the Acquired Assets and records relating thereto, and to conduct a Phase I environmental review thereof. In certain limited circumstances, Enerplus USA may seek Vendor's consent to conduct a Phase II environmental review, which consent may be withheld in Vendor's sole discretion; provided, however, if Vendor withholds such consent, subject to certain conditions, Enerplus USA may elect to exclude the affected assets and reduce the Purchase Price by the allocated value of the assets so excluded. Title and environmental defects that exceed certain minimum thresholds shall result in a downward adjustment to the Purchase Price by the amount that such defects exceed a deductible of 4% of the Purchase Price. If the net amount of title defects (as offset by any title benefits) and environmental defects (in each case, subject to a minimum threshold and aggregate deductible), exercised preferential rights, unobtained consents, assets excluded due to Vendor's refusal to consent to a Phase II and casualty losses resulting in a downward adjustment to the Purchase Price exceeds 15% of the Purchase Price, then either Enerplus USA or the Vendor may terminate the Purchase Agreement.

The Purchase Agreement contains customary conditions to closing of the Acquisition including, but not limited to: (a) the accuracy of each party's representations and warranties, and the performance of their respective covenants; and (b) no legal proceedings that would prohibit or seek substantial damages in connection with the Acquisition are pending before any governmental authority. In addition, the Purchase Agreement may be terminated by either party if the Acquisition Closing Date has not occurred by June 18, 2021.


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Enerplus USA has provided the Vendor with a deposit in the amount of US$31.2 million in support of its obligations pursuant to the Purchase Agreement (the "Deposit"). If the Acquisition is consummated, the Deposit will be applied towards the Purchase Price. If the Acquisition does not close due to a willful breach by Enerplus USA of the Purchase Agreement, or if Enerplus USA elects not to close the Acquisition despite all conditions to closing being satisfied or waived, the Vendor can either seek (a) to retain the Deposit or (b) specific performance. If the Acquisition does not close due to a willful breach by the Vendor of the Purchase Agreement, or if the Vendor elects not to close the Acquisition despite all conditions to closing being satisfied or waived, Enerplus USA can either seek (a) return of the Deposit, in addition to pursuing damages from the Vendor in an amount up to the amount of the Deposit, or (b) specific performance.

The Vendor has agreed to indemnify Enerplus USA 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 due to be performed prior to closing, subject to certain exceptions, including certain title warranties of the Vendor that will survive for two years. Enerplus USA has agreed to indemnify the Vendor after closing from and against any liabilities arising out of the ownership and operation of the Acquired Assets (whether before or after the Acquisition Closing Date), 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.

Description of the Acquired Assets

Description of the Acquired Assets

Outlined below is a description of crude oil and natural gas properties associated with the Acquired Assets, all of which are located in North Dakota. Primary U.S. crude oil properties associated with the Acquired Assets are located in the Little Knife, Murphy Creek and Russian Creek regions of North Dakota.

The Acquired Assets contain approximately 78,700 largely contiguous net acres of land in Little Knife, in Dunn County. On a production basis, approximately 65% of the Little Knife's properties comprising the Acquired Assets are operated. The Little Knife property produces a tight oil with some associated shale gas and NGLs, from both the Middle Bakken and Three Forks formations. Little Knife production averaged approximately 6,545 BOE/day in 2020 consisting of approximately 4,810 bbls/day of tight oil, approximately 811 bbls/day of NGLs and approximately 5,547 Mcf/day of shale gas. In the Little Knife region, 0.4 net wells were brought on-stream in 2020. In addition, 0.8 net wells were drilled in 2020 targeting the Middle Bakken and Three Forks formations and remain yet to be completed. Enerplus expects these 0.8 net drilled uncompleted wells to be completed and brought on production in 2021.

The Acquired Assets also contain working interests in the Murphy Creek and Russian Creek regions, which produced an average of approximately 622 BOE/day from the Middle Bakken formation in 2020, consisting of approximately 585 bbls/day of tight oil, approximately 26 bbls/day of NGLs and approximately 71 Mcf/day of shale gas.

Overall, the Acquired Assets produced an average of approximately 7,170 BOE/day in 2020 (75% tight oil, 12% NGLs and 13% shale gas). Total proved plus probable reserves associated with the Acquired Assets as at March 1, 2021 were approximately 62.7 MMBOE (49.7 MMbbls of tight oil, 7.1 MMbbls of NGLs and 35.1 Bcf of shale gas), as described in more detail below under " – Summary of Oil and Gas Reserves".

In 2020, the Vendor incurred capital expenditures (essentially all of which were development costs and not exploration costs) of approximately US$1.5 million in respect of the Acquired Assets. The Corporation


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anticipates that spending by the Corporation on these properties in 2021 following completion of the Acquisition will be in the range of US$15 million to US$20 million.

Summary of Principal Production Locations

The following table describes the average daily production from the principal producing properties and regions comprising the Acquired Assets during the year ended December 31, 2020.

Average Daily Production from Principal Properties and Regions

Products

Property/Region

    

Tight Oil

    

NGLs

    

Shale Gas

    

Total

 

(bbls/day)

(bbls/day)

(Mcf/day)

 

(BOE/day)

Little Knife, North Dakota

 

4,810

810

5,550

6,545

Murphy Creek, North Dakota

 

585

25

70

620

Russian Creek, North Dakota

 

3

-

2

3

Total

 

5,400

835

5,620

7,170

Quarterly Production History

The following table sets forth average daily gross production volumes associated with the Acquired Assets by product type, for each fiscal quarter in 2020 and for the entire year. Production decreased significantly after the second quarter of 2020 due to commodity price-related oil production curtailments and minimal development capital spending on the properties.

Year Ended December 31, 2020

Product Type

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

Annual

Tight oil (bbls/day)

6,380

5,690

4,770

4,745

5,400

Natural gas liquids (bbls/day)

760

1,050

755

785

835

Total liquids (bbls/day)

7,140

6,740

5,525

5,530

6,240

Shale gas (Mcf/day)

5,310

6,770

4,685

5,710

5,620

Total (BOE/day)

8,030

7,870

6,310

6,480

7,170

Exploration and Development Activities

In 2020, there were two gross (0.3 net) crude oil wells drilled on properties comprising the Acquired Assets.

Oil and Natural Gas Wells and Unproved Properties

As at March 1, 2021, there were 386 gross (113.6 net) producing oil wells and 49 gross (9.9 net) non-producing oil wells, which are not producing but may be capable of production, associated with the Acquired Assets. Enerplus expects that no rights to explore, develop and exploit on unproved properties associated with the Acquired Assets will expire, in the ordinary course, prior to December 31, 2021. Enerplus does not believe that a material portion of unproved properties associated with the Acquired Assets 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.

For any properties with no reserves or on unproved lands associated with the Acquired Assets, Enerplus does not believe such assets have any significant abandonment and reclamation costs, unusually high expected development costs or operating costs, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations.


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Summary of Oil and Gas Reserves

All of the reserves associated with the Acquired Assets have been independently evaluated for the Corporation in accordance with NI 51-101 by McDaniel, with an effective date of March 1, 2021 (the "McDaniel Report"). 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 of March 1, 2021, tight oil, NGLs and shale gas reserves associated with the Acquired Assets and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions pertaining to 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. Such estimates are also presented before deducting income taxes as the McDaniel Report evaluated the Acquired Assets on a stand-alone basis, without considering corporate tax rates or tax pools of the Vendor or the Corporation. 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 tight oil, NGLs and shale gas reserves associated with the Acquired Assets provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein.

The following tables set forth the estimated gross and net reserves volumes and net present value of future net revenue attributable to reserves associated with the Acquired Assets as of March 1, 2021, using forecast price and cost cases.

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

As of March 1, 2021

OIL AND NATURAL GAS RESERVES

RESERVES

CATEGORY

    

Tight Oil

Natural Gas

Liquids

Shale Gas

 

Total

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(Mbbls)

 

(MMcf)

 

(MMcf)

 

(MBOE)

 

(MBOE)

Proved Developed Producing

11,321

9,037

1,765

1,409

8,828

8,468

14,556

11,857

Proved Undeveloped

16,792

13,312

2,753

2,180

13,305

12,989

21,762

17,657

Total Proved

28,113

22,349

4,517

3,589

22,133

21,457

36,319

29,514

Probable

21,636

17,280

2,561

2,043

12,967

12,383

26,358

21,387

Total Proved Plus Probable

49,749

39,629

7,078

5,632

35,099

33,840

62,677

50,901

Notes:

(1)

Gross reserves are working interest reserves before royalty deductions.

(2)

Net reserves are working interest reserves after royalty deductions plus royalty interest reserves.

(3)

Natural Gas Liquids include Condensate volumes.


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Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves (Forecast Prices and Costs)

As of March 1, 2021

NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)

Before Deducting Income Taxes

RESERVES CATEGORY

    

0%

5%

10%

15%

20%

Unit   
Value
(1)

 

(in $ millions)

$/BOE 

Proved Developed Producing

165

141

121

105

92

$10.21

Proved Undeveloped

161

105

67

42

24

$3.79

Total Proved

326

246

188

147

117

$6.37

Probable

346

205

127

83

56

$5.95

Total Proved Plus Probable

672

451

315

229

173

$6.19

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 40o API/0.5% sulphur.

(2)

Edmonton Light Sweet 40o API/0.3% sulphur.

(3)

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

(4)

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

(5)

Escalation is approximately 2% per year thereafter.


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Undiscounted Future Net Revenue by Resources Category

The undiscounted total future net revenue by reserves category as of March 1, 2021, using forecast prices and costs, is set forth below (columns or rows may not add due to rounding):

RESERVES CATEGORY

Revenue(1)

Royalties(2)

Operating
Costs

Development
Costs

Abandonment
and
Reclamation
Costs

Future Net Revenue
Before
Income
Taxes

(in $ millions)

Proved Reserves

1,467

426

428

247

39

326

Proved Plus Probable
Reserves

2,723

785

766

447

52

672

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 March 1, 2021, 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)

187,922

8.41

Shale Gas(3)(4)

n/a

n/a

Total

187,922

Proved Plus Probable Reserves

Tight Oil(2)

315,252

7.96

Shale Gas(3)(4)

n/a

n/a

Total

315,252

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 associated with the Acquired Assets estimated for March 1, 2021 through December 31, 2021 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual production may vary from the estimates below as the actual development programs, timing and priorities on the Acquired 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 and 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
Average Daily
Production

Tight Oil

1,344 Mbbls

4,392 bbls/day

18 Mbbls

58 bbls/day

1,362 Mbbls

4,450 bbls/day

Total Crude Oil

1,344 Mbbls

4,392 bbls/day

18 Mbbls

58 bbls/day

1,362 Mbbls

4,450 bbls/day

Natural Gas Liquids

197 Mbbls

643 bbls/day

2 Mbbls

8 bbls/day

199 Mbbls

651 bbls/day

Total Liquids

1,541 Mbbls

5,035 bbls/day

20 Mbbls

66 bbls/day

1,561 Mbbls

5,101 bbls/day

Shale Gas

1,045 MMcf

3,416 Mcf/day

14 MMcf

46 Mcf/day

1,059 MMcf

3,462 Mcf/day

Total

1,715 MBOE

5,604 BOE/day

22 MBOE

73 BOE/day

1,737 MBOE

5,678 BOE/day


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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

3,780

3,624

3,780

3,624

2022

68,621

59,810

68,621

59,810

2023

84,202

67,351

84,202

67,351

2024

77,864

56,923

84,294

61,429

2025

12,124

8,232

102,110

67,401

2026

716

442

84,178

50,545

Remainder

-

-

20,106

11,244

Total

247,307

196,382

447,292

321,403

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 reserves and, in particular, on the development of undeveloped reserves associated with the Acquired Assets, 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 reserves data associated with the Acquired Assets.

In connection with its operations, the Corporation will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines, including on properties associated with the Acquired Assets. 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 reserves properties or properties with no attributed reserves associated with the Acquired Assets, and the Corporation does not anticipate its abandonment and reclamation liabilities to negatively impact reserves data associated with the Acquired Assets or its ability to develop these reserves at this time.

Marketing Arrangement and Forward Contracts

Crude oil production associated with the Acquired Assets is marketed to various buyers using a mix of negotiated contracts. Crude oil production associated with the Acquired Assets is transported to buyers by pipeline and/or truck. At times, a portion of such North Dakota crude oil production may be transported to the U.S. Gulf Coast, where it can further access export crude oil markets. NGLs associated with crude oil production volumes are marketed by midstream companies in North Dakota.

All of the natural gas production associated with the Acquired Assets was shale gas production from tight oil operations in North Dakota. These volumes are not marketed directly, as they are marketed by midstream companies in North Dakota.


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5.2Disclosure for Restructuring Transactions

Not applicable.

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

Not applicable.

Omitted Information

Not applicable.

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

Date of Report

April 16, 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, including expected purchase price, terms, and timing of 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.


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Presentation of Information in this Material Change Report

Information about the Acquired Assets

As the Corporation does not currently own the Acquired Assets, the information in this material change report relating to the Acquired Assets, has been summarized from information obtained from the Vendor and its affiliates. None of the Vendor or any of its affiliates or their respective directors, officers, employees, shareholders, members, partners, agents or other representatives (each, a "Vendor Party") makes any representation or warranty as to the accuracy or completeness of the information regarding the Acquired Assets or the Vendor contained in this material change report, and no Vendor Party was involved in the preparation or assembly of this material change report. No Vendor 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 Report on the Acquired Assets effective March 1, 2021 was prepared on behalf of the Corporation with information provided by the Corporation and other industry information available to McDaniel, and no Vendor Party participated in or provided any information to McDaniel in respect of such report.

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 information in this material change report is on "gross" basis, which are working interest share before deduction of royalties and without including any royalty interests. Unless otherwise stated, all of the production information in this material change report is on a "company interest" basis, which are working interest share before deduction of royalties and including any royalty interests. Additionally, the oil and gas production volumes associated with the Acquired Assets 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 company interest production volumes 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.


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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/day

barrels (with each barrel representing 34.972 imperial gallons or 42 U.S. gallons) per day

Bcf

billion cubic feet

BOE

barrels of oil equivalent

BOE/day

barrels of oil equivalent per day

Mbbls

one thousand barrels

MBOE

one thousand barrels of oil equivalent

Mcf

one thousand cubic feet

Mcf/day

one thousand cubic feet per day

MMbbls

one million barrels

MMBOE

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




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