INVESTOR UPDATEERF: TSX & NYSE

M A Y 2 0 2 0

This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", “estimate”, “guidance”, "may", "will", "should", "believe", "plans“ and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this presentation contains forward-looking information pertaining to the following, on the entire company basis and on an asset-level basis, as applicable: the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our

adjusted funds flow or expected free cash flow in 2020; our drilling program, including future development locations and plans, the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management programs, in 2020 and in the future; expectations regarding our realized oil and natural gas prices; future efficiencies and reserves and production growth; capital spending levels in 2020 and in the future, along with its components and impact on our production levels and land holdings; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, and our tax pools and the time at which we may pay Canadian cash taxes; net operating income and future adjusted funds flow levels, including on a per share and debt adjusted basis; future debt and working capital levels and net debt-to-adjusted funds flow ratios and adjusted payout ratios, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; the

amount and timing of future cash dividends that we may pay to our shareholders; and future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom; and our ESG initiatives, including greenhouse gas emissions and freshwater reduction targets in 2020.

The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: continued low commodity price environment or further volatility; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production to retain value, or due to low realized prices or

lack of adequate infrastructure; changes in tax or environmental laws, royalty rates, incentive programs or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserves and contingent resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; constraints on, or unavailability of, adequate pipeline and transportation capacity; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our Annual Information Form, Form 40-F, and as described under “Risk Factors and Risk Management” in our First Quarter 2020 report and 2019 Annual MD&A dated February 21, 2020 (the “2019 MD&A”).

The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions made by Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the completion and timing of proposed projects (including in-serviced dates); that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserves and resources volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to negotiate debt covenant

relief under our bank credit facility and outstanding senior notes if required; the ability to repay certain debts on the estimated timelines, or at all; the availability of third party services; and the extent of our liabilities. In addition, our expected 2020 capital expenditures and operating strategy described in this presentation is based on the rest of the year prices and exchange rate of: a WTI price of US$22.80/bbl, a NYMEX price of US$2.23/Mcf, and a USD/CDN exchange rate of 1.40. Although we believe 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 purpose of our adjusted funds flow disclosure, as well as the net operating income disclosure from both the Corporation’s Marcellus and Canadian Waterflood assets is to assist readers in understanding Enerplus’ expected and targeted

financial results, and this information may not be appropriate for other purposes.

Certain measures used in this presentation do not have a standardized meaning under United States GAAP (“U.S. GAAP”). Please refer to “Non-GAAP measures” in the “Advisories” and to our First Quarter 2020 report and our 2019 MD&A for reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP.

The forward-looking information contained in this presentation speaks only as of the date of this presentation, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Forward looking information and statements

2

Concentrated position in the Bakken core− High quality drilling inventory with large remaining opportunity set

Low financial leverage and strong liquidity− 0.8x net debt to adjusted funds flow ratio (Mar 31, 2020)(1)

Well positioned to navigate low commodity price environment− Significant operational flexibility, strong balance sheet, reduced cost structure

Disciplined returns-based capital allocation− Track record of delivering profitable growth and free cash flow

Enerplus overview

3

CDN WATERFLOODS8,200 BOE/d (94% oil)

BAKKEN49,500 BOE/d (80% oil)

MARCELLUS216 MMcf/d (100% gas)

Dual listed: TSX and NYSE

Market capitalization: C$0.8 billion

Net debt(1): C$0.7 billion

Enterprise value: C$1.5 billion

Q1 2020 production: 98,209 BOE/d (55% liquids)

Company Information

1) Non-GAAP measure. See supplemental materials and “Advisories”.2) Production volumes on map are Q1 2020. Map does not include ~4.5 MBOE/d from other assets in Canada and Colorado.

Prioritizing balance sheet strengthR E S P O N D I N G T O L O W O I L P R I C E E N V I R O N M E N T

4

$520-$570

$300

2020OriginalBudget

2020ReducedBudget

~45% REDUCTION

TO CAPITAL BUDGET

Reduction to capital activity to protect liquidity2020e capital spending (C$ millions)

45% reduction to original capital budget− Suspended all operated drilling & completions activity in North Dakota

Strong liquidity− ~US$100MM of cash and US$600MM undrawn bank facility at Q1 2020

Robust commodity hedging position− Forecast hedging gains of ~$150MM(2) in 2020

Reduced cash costs − Lower operating costs through improved workflow and service cost reductions

− Lower G&A costs from reduced cash compensation for Board, executives and employees

Significant operational flexibility to manage production during volatility− Adjusting production to protect against negative margins and preserve shareholder value

Advantaged position for rapid future capital deployment when conditions improve− 27 net drilled uncompleted wells in inventory in North Dakota

WELL POSITIONED TO NAVIGATE CHALLENGING MARKET CONDITIONS

1) Non-GAAP measure. Please see supplemental materials and “Advisories”.2) Based on recent forward strip oil prices.

2020 guidance withdrawn given current market uncertainty

Balance sheet strength a competitive advantageB A L A N C E S H E E T & L I Q U I D I T Y P O S I T I O N

1) At March 31, 2020. Non-GAAP measure. See supplemental materials and “Advisories”.2) Cash position of US$101MM translated from reported C$142MM using FX rate of 1.41. Senior notes are rated NAIC 2 (investment grade) by the National Association of Insurance Commissioners; rank equally with the bank credit facility.

5

$82 $82$101

$81 $81

$21 $21$0

$100

$200

$300

$400

$500

$600

$700

$800

Liquidity 2020 2021 2022 2023 2024 2025 2026

Cash Bank Credit Facility Senior Notes

Significant liquidityUS$ millions - Cash, credit facility and senior notes (Mar 31, 2020)(2)

CASH$101

Solid financial position

− Significant liquidity and low leverage

− Net debt/adjusted funds flow: 0.8x(1)

Debt comprised of senior notes− Relatively flat maturity profile

− 2020 maturity can be repaid with cash

US$600MM credit facility is undrawn

CREDIT FACILITY$600 Million(Undrawn)

Price risk managementC O M M O D I T Y H E D G I N G S U M M A R Y

1) The total average deferred premium on outstanding 2020 hedges is US$1.67/bbl from Apr 1, 2020 to Dec 31, 2020. 6

Swaps Put Spreads Three-way Collars

Period Volume(Mbbl/d)

Sold Swap(US$/bbl)

Volume(Mbbl/d)

Sold Put(US$/bbl)

Purchased Put(US$/bbl)

Volume(Mbbl/d)

Sold Put(US$/bbl)

Purchased Put(US$/bbl)

Sold Call(US$/bbl)

Apr 1 – Jun 30, 2020 9.5 $57.37 16.0 $46.88 $57.50 - - - -

Jul 1 – Sep 30, 2020 7.0 $36.02 16.0 $46.88 $57.50 5.0 $48.00 $56.25 $65.00

Oct 1 – Dec 31, 2020 - - 16.0 $46.88 $57.50 5.0 $48.00 $56.25 $65.00

CRUDE OIL HEDGES (WTI)(1)

Forecast hedging gains of ~$150 million in 2020, based on recent forward strip oil prices

In addition to the financial contracts above, Enerplus has fixed physical differential sales agreements for ~13,000 bbl/d of oil in North Dakota at WTI less ~US$5.00/bbl for the remainder of 2020

High return growth, free cash flow and low leverageT R A C K R E C O R D

1) Non-GAAP measure. Please see supplemental materials and “Advisories”.7

4189%oil

5091% oil

5591%oil

44

4346

85

93

101

2017 2018 2019

Liquids Natural gas

16% 3-year liquids production CAGR since 2016

High return oil growthProduction, MBOE/d

$316

$66

$160

$90

2017 2018 2019 Total

Focus on free cash flowFree cash flow(1), C$ millions

$29 $29 $28

$79

$179

2017 2018 2019

Dividends Share repurchases

Return of capitalC$ millions

>$300MMCumulative free cash

flow since 2017

~10%Of shares outstanding repurchased since Q3 2018

0.6x0.4x

0.6x0.8x

0x

1x

2x

3x

2017 2018 2019 Q12020

Low financial leverageNet debt to adjusted funds flow ratio(1)

0.8xLeverage ratio at Q1 2020

Material focus areas

8

ESGMATERIAL

FOCUS AREAS

Reduce GHG emissions intensity through technological innovation and operational efficiency.

Targeting a 10% reduction in GHG emissions per BOE in 2020(1)

Greenhouse Gas Emissions

Manage water use by deploying technology to reduce and reuse freshwater.

Targeting a 15% reduction in freshwater use per well completion, on average, in North Dakota in 2020

Water Management

CultureContinue to elevate our culture of accountability ensuring strong alignment of shared values.

Promote an inclusive and supportive workplace

Measure employee engagement and understand where gaps exist in culture alignment

Stakeholder EngagementCreate positive and sustainable impacts in the communities in which we operate.

Job creation

Improved infrastructure

Direct funding/community supportHealth and SafetyWe are committed to building a workplace where all injuries can be prevented.

Ambition is zero incidents

Board Expertise & EngagementEnsure the Board is highly-engaged and accountable, with a comprehensive and diverse skill-set.

Independent and diverse

Essential skills

Strong engagement

Effective succession

E N V I R O N M E N T A L , S O C I A L & G O V E R N A N C E

1) Enerplus’ GHG emissions reduction target addresses scope 1 and 2 emissions. Scope 1 emissions are direct emissions from owned and operated facilities. Scope 2 emissions are indirect emissions from the generation of purchased energy for the Company’s owned and operated facilities.

North Dakota and Montana – Bakken / Three ForksW I L L I S T O N B A S I N O V E R V I E W

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WILLISTON BASIN OVERVIEW

Mountrail

Dunn

Billings

Mckenzie

Williams

DivideBurke

Richland

Roosevelt

Sheridan

Dawson

MO

NT

AN

A

NO

RT

H D

AK

OT

A

FORT BERTHOLD, ND

Tier 1 acreage position

Large remaining opportunity set

Q1 2020 production: 47 Mboe/d (81% oil)

SLEEPING GIANT, MT

Modest capital expenditures

Low decline, strong free cash flow generator

Q1 2020 production: 3 Mboe/d (73% oil)

SLEEPING GIANT FORT BERTHOLD

Acreage position concentrated in the core of the play

− 66,300 net acres

− Top quartile basin well performance

Singularly unique asset in Bakken core

− High quality inventory with running room

Tier 1 acreage positionF O R T B E R T H O L D – B A K K E N / T H R E E F O R K S O V E R V I E W

1) Production in 2016 and prior has been adjusted for divestments.10

ERF BAKKEN POSITION – FORT BERTHOLD, ND

Light oil production growthEnerplus North Dakota production, Mboe/d(2)

45.6

0

10

20

30

40

50

2014 2015 2016 2017 2018 2019

FO

RT

BE

RT

HO

LD IN

DIA

N R

ES

ER

VA

TIO

N

Mckenzie

Dunn

McleanMountrail

15% GROWTH(2019 vs 2018)

Track record of continued efficiency gains

Solid execution YTD resulted in US$800K reduction in well costs compared to 2019(1)

Strong execution delivering capital efficiency gainsF O R T B E R T H O L D C A P I T A L E F F I C I E N C Y I M P R O V E M E N T S

11

0

3,000

6,000

9,000

12,000

15,000

18,000

21,000

0 2 4 6 8 10 12 14 16 18 20

Dep

th (

ft)

Days

2017 Average2018 Average2019 Average2020 AveragePacesetter

Drilling efficiency - continuing to drill fasterDrilling days vs. depth (spud to rig release)(2)

4.9

6.7

8.8

10.5

0

2

4

6

8

10

12

2018Average

2019Average

2020Average

Pacesetter

Stag

es/

day

Completion efficiency – more stages per dayStages per day

80% IMPROVEMENT

(2020 vs 2018)

>6 days faster(2020 vs 2017)

1) 2020 well costs expected to average US$6.8million (for a 2-mile lateral including drilling, completion and facilities costs).2) Based on two-mile lateral wells.

Low existing well density and large remaining opportunity

Running room to support high return growthF O R T B E R T H O L D D R I L L I N G I N V E N T O R Y

1) Inventory as at December 31, 2019. Gross (net) locations includes 196 (167) proved plus probable undeveloped reserves locations (includes drilled uncompleted wells). 113 (95) best estimate contingent resources locations and 99 (79) unbooked future locations. See “Advisories”.

2) DSU is a drilling spacing unit. Well locations per DSU is a simple average and may vary by specific DSU.

12

High quality drilling inventory(1)

Gross operated inventory locations

0

100

200

300

400

500

2020 Program Remaining Undrilled Inventory

Current Density: ~4 wells/DSU

Ultimate Density: ~10 wells/DSU

Low Existing Well Density(2)

M. BAKKEN

TF 1

TF 2

TF 3

Certain deeper bench locations included in inventory in acreage where these zones are productive

Development Plan per Spacing Unit

18 operated wells online

~410 operated locations

Maintaining strong well performance at lower cost F O R T B E R T H O L D W E L L P E R F O R M A N C E

1) Well economics are based on the average 2P reserves booked per undeveloped location for a 2-mile lateral (~730 mboe) and a total well cost of US$6.8MM.2) Well cost for a 2-mile lateral including drill, complete, tie-in and facilities costs.

13

Cumulative oil production per wellEnerplus two-mile lateral well performance

-

100

200

300

400

500

0 100 200 300 400 500 600

Cum

ulat

ive

oil p

rodu

ctio

n (m

bbls

)

Producing days

2017 wells 2018 wells 2019 wells 2020 wells2017 Avg 2018 Avg 2019 Avg 2020 Avg

$8.1

$6.8

2017 2020 YTD

$1.3 MILLIONWELL COST REDUCTION

Well economics(1)

WTI Oil Price $50/bbl $60/bbl

Payout: 2.2 yrs 1.3 yrs

IRR: 40% 80%

Breakeven (10% IRR): $38/bbl WTI

Total Well Costs (US$MM)(2)

Non-operated position in Marcellus dry gas core

− 34,000 net acres

− Q1 2020 production: 216 MMcf/d

Low cost, highly productive inventory

− >10 year drilling inventory(1)

Consistent free cash flow generation

Anticipating y-o-y production declines due to limited capital activity

− ~50% reduction in capex y-o-y given NYMEX pricing weakness

Core acreage position in the Marcellus dry gas windowM A R C E L L U S O V E R V I E W

1) 59 net future drilling locations as at December 31, 2019. Includes 22 proved plus probable undeveloped reserves locations and 37 best estimate contingent resources locations. See “Advisories”.2) Net operating income (“NOI”) is a Non-GAAP measure. See supplemental materials and “Advisories”. 2020e NOI is based on US$2.16/Mcf NYMEX.

14

MARCELLUS POSITION – NE PENNSYLVANIA

SusquehannaBradford

Sullivan

Lycoming

Wyoming

Enerplus Marcellus productionMMcf/d

195 198208

227216

2016 2017 2018 2019 Q1 2020

Consistent free cash flowCapex vs net operating income (US$MM)(2)

$0

$25

$50

$75

$100

2016 2017 2018 2019 2020e

Capex NOI

Low cost structure and competitive natural gas price differential is supporting margins despite lower NYMEX prices

Asset is expected to continue to generate free cash flow in 2020

Cash margin supported by low cost structure, competitive basisM A R C E L L U S M A R G I N

15

Marcellus cash marginUS$/Mcf

$0.29$0.51

$1.06$1.31

$1.00

$0.61

$1.00$1.02

$1.29

$1.34

$1.24

$1.19

$1.37 $0.93

$0.76$0.43

$0.39

$0.45

$2.66$2.46

$3.11 $3.08

$2.63

$2.25

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

2015 2016 2017 2018 2019 2020e

Cash Margin Opex, Gathering, Trans, Royalty

Basis Differential NYMEX Benchmark Price

-

1

2

3

4

5

6

7

8

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Bcf

per

wel

l

Months on Production

Lateral Length < 5,000 ft

Lateral Length 5,000 ft - 7,500 ft

Lateral Length > 7,500 ft

Capital efficient and highly productive drilling inventoryM A R C E L L U S W E L L R E S U L T S

1) Based on >145 wells on production since January 2017.2) Well economics are based on the average 2P reserves booked per undeveloped location for a 6,300 ft lateral (~16 Bcf) and a total well cost of US$6.5MM.

16

Marcellus well performance 2017-2020 Average cumulative production per well(1)

Well economics(2)

NYMEX Gas Price (US$): $2.50/Mcf $3.00/Mcf

Payout: 3.4 yrs 2.0 yrs

IRR: 24% 54%

Breakeven US$ (10% IRR): $2.19/Mcf

60 wells

65 wells

45 wells

Balanced Pricing ExposureE N E R P L U S ’ M A R C E L L U S N A T U R A L G A S M A R K E T S

17

48%

29%

18%

5%

In basin pricing at Leidy

Exposure to robust winter demand center in the New Jersey market

Firm transport to the Gulf coast market

Enerplus is well positioned to capitalize on the improving natural gas price outlook

MARKETLeidyTZ6 Non-NY

Gulf CoastOther

-$1.20

-$1.00

-$0.80

-$0.60

-$0.40

-$0.20

$0.00

$0.20

Q117

Q217

Q317

Q417

Q118

Q218

Q318

Q418

Q119

Q219

Q319

Q419

Q120

Q220

Q320

Q420

2020e pricing exposure% of expected Marcellus sales(1)

Enerplus realized Marcellus differential(2)

US$/Mcf, average portfolio differential to NYMEX

Avg. -$0.76

Avg. -$0.43

1) Pricing exposure is approximate.2) Differential is shown excluding transportation cost. Enerplus’ Marcellus firm transportation cost is approximately US$0.18-$0.20/Mcf.

Avg. -$0.39 2020e -$0.45

11 11 1110 10 10

9 8

12 12 1211 11 12

10 9

2012 2013 2014 2015 2016 2017 2018 2019

Assets under water or polymer flooding

− Significant resource: 0.8 bn bbls OOIP(1)

− Low decline oil production

Portfolio optimized to focus on highest return, strong cash flow generating assets− Improved cost structures have driven margins higher

Large oil in place, low decline productionC A N A D I A N O I L W A T E R F L O O D P O R T F O L I O

1) OOIP is discovered original oil in place and is internally estimated. 2) Production and net operating income (“NOI”) is from retained assets (excludes assets divested). NOI is a Non-GAAP measure. See supplemental materials and “Advisories”.

18

CANADIAN WATERFLOODS

Strong cash flow generationNet Operating Income minus Capex(2) (C$MM)

Low decline oil productionMboe/d(2)

OIL

GAS/NGL

>US$350 MILLIONIN FREE CASH FLOW

SINCE 2012

ANTE CREEK

GILTEDGE

CADOGAN

MEDICINE HAT

FREDA LAKEAlbertaBritish Columbia

Saskatchewan

>$450 MILLIONIN FREE CASH FLOW

SINCE 2012

~$400 MILLIONIN FREE CASH FLOW

SINCE 2012$0

$100

$200

$300

$400

$500

2012 2013 2014 2015 2016 2017 2018 2019

>$450 MILLIONIN FREE CASH FLOW

SINCE 2012

~40,000 net acres in NW Weld County

− Low entry price achieved through leasing and farm-in activity

− Significant oil in place through all Niobrara benches and Codell

Initial well results compare favorably to core DJ oil rates

~400 gross drilling locations(1) identified in southern acreage− Based on 6-Codell and 6-Niobrara density

− Additional benches with significant oil saturations offer upside

Focused on enhancing well economics through further drilling & completion optimization− Line of sight to competitive cost structures

Northern extension of Wattenberg fieldE M E R G I N G O P P O R T U N I T Y – D J B A S I N

1) Internally identified future drilling locations. Average working interest expected between 40% - 70%.19

DJ BASIN

2017/2018 - 5 wells online(4 Codell, 1 Niobrara)

2019 - 5 wells online(4 Codell, 1 Niobrara)

DENVER

WELD

MORGAN

ADAMS

WYOMING

COLORADO

Returns and value focused

20

I N V E S T M E N T H I G H L I G H T S

1) Production volumes on map are Q1 2020. Map does not include ~4.5 MBOE/d from other assets.

CDN WATERFLOODS8,200 BOE/d (94% oil)

BAKKEN49,520 BOE/d (80% oil)

MARCELLUS216 MMcf/d (100% gas)

Concentrated acreage footprint in the Bakken core

Large remaining development opportunity

Low financial leverage and strong liquidity

Well positioned to navigate low oil price environment

Disciplined returns-based capital allocation

SUPPLEMENTAL INFORMATION

21

7% 7% 8% 8%

-1%

5%

8%

3%

10%

18%

23%

-8%

12%

-10%

-5%

0%

5%

10%

15%

20%

25%

2016 2017 2018 2019

Track record of outsized returns vs. S&P 500R E T U R N O N C A P I T A L E M P L O Y E D

1) Return on capital employed (ROCE) is a Non-GAAP measure. See supplemental materials and “Advisories”. S&P 500 and S&P 500 Energy return on capital employed sourced from Bloomberg.2) Enerplus’ 2019 impairment adjusted ROCE excludes the impact of a $451MM non-cash goodwill impairment related to Enerplus’ Canadian reporting unit due to asset divestments, the shut-in of the Tommy Lakes asset, and

lower forecast commodity prices.

22

Enerplus

S&P 500S&P 500 Energy

Return on capital employed(1)

Enerplus goodwill impairment adjusted(2)

The Board of Directors

23

Karen E. Clarke-Whistler (Director since December 2018)Corporate Governance & Nominating CommitteeSafety & Social Responsibility Committee

Michael R. Culbert (Director since March 2014)Audit & Risk Management CommitteeCompensation & Human Resources CommitteeCorporate Governance & Nominating Committee

Ian C. DundasPresident and CEO

Judith D. Buie (Director since January 2020)Audit & Risk Management CommitteeReserves Committee

Robert B. Hodgins (Director since November 2007)Audit & Risk Management CommitteeCompensation & Human Resources CommitteeCorporate Governance & Nominating Committee

Susan M. MacKenzie (Director since July 2011)Audit & Risk Management CommitteeReserves CommitteeSafety & Social Responsibility Committee

Jeffrey W. Sheets (Director since December 2017)Audit & Risk Management CommitteeCompensation & Human Resources CommitteeSafety & Social Responsibility Committee

Sheldon B. Steeves (Director since June 2012)Reserves CommitteeSafety & Social Responsibility Committee

Hilary A. Foulkes (Director since February 2014)

Board Chair (effective May 7, 2020)

Elliott Pew (Director since September 2010)Previous Board Chair

ESG - Board oversight

24

Audit & Risk Management Committee

Compensation & Human Resources

Committee

Corporate Governance &

Nominating Committee

Reserves Committee

Safety & Social Responsibility

Committee

Board Committees

Greenhouse Gas Emissions

Water Management

CultureStakeholder Engagement

Health & Safety

Board Expertise & Engagement

ESG oversight by the Board of Directors with material focus areas mapped to the applicable committee

Sustainability reporting

25

5 YEARSOF SUSTAINABILITY REPORTING

Summary of operational and financial metrics

26

2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020Average Benchmark Prices

WTI Crude Oil (US$/bbl) 50.95$ 62.87$ 67.88$ 69.50$ 58.81$ 64.77$ 54.90$ 59.81$ 56.45$ 56.96$ 57.03$ 46.17$ NYMEX Natural Gas (US$/Mcf) 3.11$ 3.00$ 2.80$ 2.90$ 3.64$ 3.09$ 3.10$ 2.64$ 2.23$ 2.50$ 2.63$ 1.95$

Production(1)

Oil (mbbl/d) 36,935 37,443 45,242 48,867 49,968 45,424 41,105 48,141 55,023 54,344 49,704 49,044Natural gas liquids (mbbl/d) 3,858 4,085 4,808 4,563 4,483 4,486 4,383 4,720 5,098 5,502 4,929 5,346Natural Gas (MMcf/d) 263,506 261,310 256,995 260,591 260,453 259,837 258,568 287,000 282,360 285,537 278,451 262,913Total (MBOE/d) 84,711 85,080 92,883 96,861 97,860 93,216 88,583 100,694 107,181 107,436 101,042 98,209

% Crude oil and natural gas liquids 48% 49% 54% 55% 56% 54% 51% 52% 56% 56% 54% 55%

Selected Financial Results (C$/BOE)Oil and natural gas sales(2) 36.93$ 42.91$ 48.13$ 52.32$ 45.43$ 47.35$ 44.70$ 44.00$ 40.75$ 41.64$ 42.65$ 31.96$ Royalties and production taxes (8.91)$ (10.41)$ (12.08)$ (13.39)$ (11.58)$ (11.92)$ (10.48)$ (11.26)$ (10.80)$ (10.93)$ (10.88)$ (8.16)$ Commodity hedging 0.28$ 1.33$ (2.28)$ (2.68)$ (0.31)$ (1.05)$ 1.32$ (0.13)$ 0.53$ 0.07$ 0.42$ 3.69$ Cash operating expenses (6.39)$ (7.02)$ (7.21)$ (6.80)$ (6.99)$ (7.00)$ (8.75)$ (7.84)$ (7.06)$ (8.05)$ (7.88)$ (8.84)$ Transportation costs (3.60)$ (3.52)$ (3.56)$ (3.70)$ (3.71)$ (3.63)$ (3.92)$ (4.02)$ (3.96)$ (3.82)$ (3.93)$ (3.95)$ Netback(3) 18.31$ 23.29$ 23.00$ 25.75$ 22.84$ 23.75$ 22.87$ 20.75$ 19.46$ 18.91$ 20.38$ 14.70$ Cash general and administrative expenses (1.63)$ (1.72)$ (1.44)$ (1.35)$ (1.40)$ (1.47)$ (1.55)$ (1.26)$ (1.19)$ (1.34)$ (1.32)$ (1.37)$ Cash share-based compensation (0.03)$ (0.25)$ (0.05)$ 0.02$ 0.23$ (0.01)$ (0.17)$ 0.07$ - 0.01$ (0.02)$ 0.31$ Interest, FX and other (1.24)$ (1.05)$ (0.95)$ (0.81)$ (0.90)$ (0.92)$ (0.68)$ (0.79)$ (0.49)$ (0.89)$ (0.72)$ (0.97)$ Current inome tax recovery / (expense) 1.55$ (0.01)$ (0.01)$ (0.01)$ 3.03$ 0.80$ 0.69$ 1.52$ - 1.41$ 0.91$ -Adjusted Funds Flow(3) 16.96$ 20.26$ 20.55$ 23.60$ 23.80$ 22.15$ 21.16$ 20.29$ 17.78$ 18.10$ 19.23$ 12.67$

Notes:(1) Based on Company interest production volumes. See "Basis of Presentation" section in the MD&A.(2) Before transportation costs, royalties and the effects of commodity price derivatives.(3) Please see "Non-GAAP Measures" section in the MD&A.

Reconciliation of return on capital employed

27

(CDN$ millions) 2016 2017 2018 2019

Net Income 397.4$ 237.0$ 378.3$ (259.7)$ Add: Interest expense 45.4$ 38.7$ 36.8$ 33.9$ Add: Income tax expense (current and deferred) (237.2)$ 82.0$ 103.2$ 47.9$ Net income before interest and tax - (a) 205.7$ 357.7$ 518.3$ (177.9)$

Goodwill impairment -$ -$ -$ 451.1$ Net income before interest and tax adjusted for goodwill impairment - (a)* 205.7$ 357.7$ 518.3$ 273.2$

Shareholders' Equity 1,460.5$ 1,600.8$ 2,001.0$ 1,471.6$ Average Shareholders' Equity(1) - (b) 1,179.1$ 1,530.6$ 1,800.9$ 1,736.3$

Shareholders' Equity adjusted for goodwill impairment 1,460.5$ 1,600.8$ 2,001.0$ 1,922.7$ Average Shareholders' Equity adjusted for goodwill impairment(1) - (b)* 1,179.1$ 1,530.6$ 1,800.9$ 1,961.8$

Long-term debt 739.3$ 644.7$ 636.8$ 500.6$ Add: Working capital deficit excluding cash and current derivative assets and liabilities 94.4$ 107.6$ 143.1$ 210.4$ Less: Cash (393.3)$ (346.5)$ (363.3)$ (369.1)$ Net Debt 440.4$ 405.8$ 416.6$ 341.9$ Average Net Debt(1) - (c) 880.3$ 423.1$ 411.2$ 379.3$

Return on Capital Employed - (a) / [(b)+(c)] 10% 18% 23% -8%Return on Capital Employed adjusted for goodwill impairment - (a)* / [(b)*+(c)] 10% 18% 23% 12%

Notes:(1) Equals the average of the current and immediately preceding year

AssumptionsAll amounts are stated in Canadian dollars unless otherwise specified.

Barrels of Oil Equivalent and Cubic Feet of Gas EquivalentThis presentation contains references to “Mcf” (million cubic feet), “Bcf” (billion cubic feet), “bbl” (barrel of oil) and "BOE" (barrels of oil equivalent) in total and on a per day (“/d”) basis. Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1bbl) when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. 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 thewellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. “Mbbl” means “thousand barrels of oil; "MBOE" and "MMBOE" mean"thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively.

Non-GAAP MeasuresIn this presentation, we use the terms “return on capital employed (ROCE)”, “adjusted funds flow", “net debt to adjusted fun ds flow ratio”, “netback”, “net operating income”, and "free cash flow" as measures to analyze leverage, liquidity and operating performance. These measuresdo not have any standardized meaning under United States GAAP (“U.S. GAAP”) and are therefore, considered Non-GAAP measures. “Adjusted funds flow” is calculated as cash flow from operating activities but before changes in non-cash operating working capital and assetretirement obligation expenditures. “Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash, divided by a trailing 12months of adjusted funds flow. “Netback” and “net operating income” are calculated as oil and gas revenues after deducting royalties, operating costs and transportation expenses. “Free cash flow” is calculated as “adjusted funds flow” less exploration and development capitalspending (refer to “Non-GAAP Measures” in the First Quarter of 2020 and the 2019 Annual MD&A). The ROCE calculation is shown on the previous slide (27).

Enerplus believes that, in addition to cash flow from operations, net earnings and other measures prescribed by U.S. GAAP, the terms “ROCE”, “adjusted funds flow", “net debt to adjusted funds flow ratio”, “netback”, “net operating income”, and "free cash flow“ are usefulsupplemental measuresas they provide an indication of the results generated by Enerplus' principal business activities. However, certain of these measures are not recognized by U.S. GAAP and do not have standardizedmeaning prescribed by U.S. GAAP and, therefore, may not becomparable to similar measures calculated and presented by other issuers. For reconciliation of Non-GAAP measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see additional disclosure andreconciliations to certain of these “Non-GAAP Measures” in the First Quarter of 2020 and the 2019 Annual MD&A.

Presentation of Production and Reserves InformationUnder U.S. GAAP, oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under IFRS and Canadian industry protocol, oil and gas sales and production volumes are presented on a gross basis beforededuction of royalties. To remain comparable with our Canadian peer companies, the summary results contained within this presentation presents our production and BOE measures on a before royalty “company interest “ basis. In addition, initial test results and productionperformance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate recovery.

Readers are cautioned that the average initial production rates contained in this presentation are not necessarily indicative of long-term performance or of ultimate recovery.

All production volumes and revenues presented herein are reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest. Unless otherwise specified, all reserves volumes in this presentation (and all information derivedtherefrom) are based on “gross reserves" using forecast prices and costs. “Gross reserves" (as defined in Na tional Instrument 51-101 – S tandards of Disclosure for Oil and Gas Activities ("NI 51- 101")), being Enerplus’ working interest before deduction of any royalties. Our oil and gasreserves statement for the year ended December 31, 2019 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, and is contained within our Annual Information Form for the year ended December 31, 2019 ("our AIF")which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are alsourged to review the 2019 MD&A and financial statements filed on SEDAR and as part of our Form 40-F on EDGAR for more complete disclosure on our operations.

Discovered Petroleum Initially-In-Place, Discovered Original Oil-In-Place and Discovered Original Gas-In-PlaceDiscovered Original Oil-in-Place (“OOIP” ) is not defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP, as defined under NI 51-104. Discovered OOIP pertaining to ourCanadian waterflood assets are estimates by internal qualified reserves evaluators, combined for all Canadian waterflood assets.

Advisories

28

Contingent Resources Estimates

This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation

Handbook (the "COGE Handbook") as "tho se 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 ultimate recovery rates, 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 evaluation stage. All of our contingent resources estimates are economic using

established technologiesand based on the average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2020. Enerplus expects to develop these contingent resources in the coming years however it is too early in their

development for all of these resources to be classified as reserves at this time. A portion of these contingent resources are part of continuous development by the Company and are categorized as contingent resources primarily due to

development timelines that go beyond what is already assigned as undeveloped reserves. There is uncertainty that Enerplus will produce any portion of the volumes currently classified as “contingent resources”. “Development

pending contingent resources” refer to a “contingent resources” project maturity sub-class for a particular project where resolution of the final conditions for development are being actively pursued (there is a high chance of

development) and the project is expected to be developed in a reasonable timeframe. The “contingent resources” estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered,

effective as of December 31, 2019. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are

used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

For additional information regarding the primary contingencies which currently prevent the classification of Enerplus’ disclosed “contingent resources” associated with Enerplus’ Marcellus shale gas properties, Enerplus’ Fort Berthold

properties, and a portion of Enerplus’ Canadian crude oil properties as reserves and the positive and negative factors relevant to the “contingent resources” estimates, see Appendix A to Enerplus’ AIF, a copy of which is available

under Enerplus’ SEDAR profile at www.sedar.com, and Enerplus’ Form 40-F, a copy of which is available under Enerplus’ EDGAR profile at www.sec.gov.

Advisories continued and investor contacts

29

Investor Relations Contacts

Drew MairManager, Investor Relations403-298-1707

Krista NorlinSenior Investor Relations Analyst403-298-4304

Email: investorrelations@enerplus.com

Drilling InventoryDrilling locations associated with proved plus probable undeveloped reserves have been evaluated or reviewed by Enerplus’ independent qualified reserves evaluators in accordance with the COGE Handbook. Drilling locations associated with unrisked “best estimate” economic

contingent resources in “development pending” project maturity sub-class pertaining to Canadian waterflood assets and Fort Berthold have been evaluated by internal qualified reserves evaluators and audited by Enerplus’ independent qualified reserves evaluators, McDaniel &

Associates Ltd, in accordance with the COGE Handbook. Drilling locations associated with unrisked “best estimate” economic contingent resources in “development pending” project maturity sub-class pertaining to the U.S. Shale Gas-Marcellus been evaluated by Enerplus’independent qualified reserves evaluators, Netherland, Sewell & Associates, Inc, in accordance with the COGE Handbook. Unbooked future drilling locations are not associated with any reserves or contingent resources of Enerplus, and have been identified by internal qualified

reserves evaluators and have not been audited by Enerplus’ independent qualified reserves evaluators.

NOTICE TO U.S. READERSThe oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United S tates or o ther fo reign disclosure standards. Reserves categories such as

"proved reserves" and "probable reserves" may be defined differently underCanadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules. In addition, under Canadian disclosure requirements and industry practice,reserves and production are reported using gross (o r, as noted above with respect to production information, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production

using net volumes, after deduction of applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices and escalating costs be used for reserves evaluations, while the SEC mandates the use of an unweighted average of theclosing prices on the first day of each of the 12 months prior to the end of the reporting period, with the option of also disclosing reservesestimates based upon future or other prices and constan t costs. Additionally, the SEC prohibits disclosure of oil and gas resources in SEC filings,

whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, con tingent resources, see “Contingent ResourcesEstimates” above.