INVESTOR UPDATE ERF: TSX & NYSE Forward looking information and - - PowerPoint PPT Presentation

INVESTOR UPDATE

ERF: TSX & NYSE S E P T E M B E R 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 Second Quarter 2020 report, or 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

• perations 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

• f 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 of: WTI of US$41.19/bbl, a NYMEX price of US$1.94/Mcf, and a USD/CDN exchange rate of 1.35. 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 Second 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

−

1.0x net debt to adjusted funds flow ratio (Jun 30, 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 DN W WATERFLOODS DS

6,300 BOE/d (94% oil)

BAKKEN

44,080 BOE/d (81% oil)

MARCELLU LLUS

197 MMcf/d (100% gas)

Dual li l listed: TSX and NYSE Mar arket c cap apital alizat ation: C$0.9 billion Net et d debt ebt(1)

1): C$0.6 billion

Enter erpr prise v e value: e: C$1.5 billion Q2 2 202 020 pr 0 production:87,360 BOE/d (55% liquids)

Com

• mpany Infor
• rmation
• n

1) Non-GAAP measure. See supplemental materials and “Advisories”. 2) Production volumes on map are Q2 2020. Map does not include ~4.2 MBOE/d from other assets in Canada and Colorado.

Q2 2020 - Highlights

1) Based on cash position of US$4.5MM and US$599MM undrawn on credit facility. 2) Non-GAAP measure. Please see supplemental materials and “Advisories”. 3) Expect 23 net operated DUCs in North Dakota and 3 net operated DUCs in the DJ Basin at year-end 2020.

4

RESILIENT PRODUCTION ON STRONG LIQ IQUID IDIT ITY CAP APITAL AL DIS ISCIP IPLINE INE WELL LL POSITIONED FOR 20 2021 21

• Q2 total production of 87 MBOE/d (48 Mbbl/d liquids)
• 2020 guidance reinstated: 88-90 MBOE/d (49-50 Mbbl/d liquids)
• Liquidity of ~US$600MM(1)
• Net debt /adjusted funds flow ratio at 1.0x(2)
• Maintained $300MM capital budget in 2020
• Generated $30MM in free cash flow in Q2, more forecast in H2 2020(2)
• ~$300MM maintenance capital estimate to keep liquids flat to H2 2020
• Exiting 2020 with 26 net DUCs(3)

Solid id e execu cutio ion a and fin inancia cial r resil ilie ience

Balance sheet strength a competitive advantage

B 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 June 30, 2020. Non-GAAP measure. See supplemental materials and “Advisories”. 2) Cash position of ~US$4.5MM translated from reported C$6.2MM using FX rate of 1.36. Senior notes are rated NAIC 2 (investment grade) by the National Association of Insurance Commissioners; rank equally with the bank credit facility.

5

$82 $101 $81 $81 $21 $21

$0 $100 $200 $300 $400 $500 $600 $700 Liquidity 2021 2022 2023 2024 2025 2026 Cash Bank Credit Facility Senior Notes

Signif ificant l liquidity

US$ millions - Cash, credit facility and senior notes (Jun 30, 2020)(2)

• Solid financial position

− Significant liquidity and low leverage − Net debt/adjusted funds flow: 1.0x(1)

• Debt comprised of senior notes

− Relatively flat maturity profile − 2020 maturity of US$82MM repaid in the second quarter − No additional repayments until 2021

CREDIT IT FACIL ILITY ITY

$599 Million (Undrawn)

~$600M 00MM

LIQUIDITY POSITION

Prudently managing volatility in 2020 – well positioned for 2021

1) Well counts are net operated. TILs are turned in line wells (brought on production) 2) Maintenance capital is the investment required to keep liquids production flat in 2021 on an annualized basis. 6

54 54 48 48 ~ 4 ~ 48 44 39 ~ 37

• 20

40 60 80 100 Q1 2020 Q2 2020 H2 2020e 2021 Liquids production Natural gas production

20 2020 20 pro roduction o

• utlook a

k and 20 2021 21 maintenance c capital(1

(1)

MBOE/d

• Decisive actions taken through H1

to preserve financial strength and protect value

• Maintained focus on strong

execution, safe operations

• H2 liquids production ~flat to Q2
• 2021 maintenance capital

estimated at ~$300MM to keep liquids volumes flat to H2 2020

Executed Q1 plan (18 drills, 9 TILs in ND) Suspended activity Curtailed production (1 drill, 7 TILs in ND) Curtailed volumes restored (4 TILs in ND)

~$300 M MIL ILLIO ION

2021 maintenance capital(2) Includes allocation for:

• drilling to set up 2022
• Marcellus capital

Price risk management

C 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$1.75/bbl from Jul 1, 2020 to Dec 31, 2020 and US$0.03/bbl from January 1, 2021 to June 30, 2021.

7

Sw Swaps Put Sp Spreads Th Three-way ay C Collar ars Period

• d

Vo Volume (Mbbl/d) So Sold Sw Swap (US$/bbl) Vo Volume (Mbbl/d) So Sold P Put (US$/bbl) Pur urchased P Put ut (US$/bbl) Vo Volume (Mbbl/d) So Sold P Put (US$/bbl) Pur urchased P Put ut (US$/bbl) Sold ld C Call ll (US$/bbl) Ju Jul 1 1 – Sep 3 30, 0, 2 202 020 7.0 $36.02 16.0 $46.88 $57.50 5.0 $48.00 $56.25 $65.00 Oc Oct 1 1 – Dec 3 31, 20 2020 20

• 16.0

$46.88 $57.50 5.0 $48.00 $56.25 $65.00 Jan 1 n 1 – Jun 30, 0, 2 202 021 6.0 $32.00 $40.00 $50.00

CRUDE DE OIL HEDGES (WTI)(1)

• In addition to the financial contracts above, Enerplus has fixed physical differential sales agreements for ~16,000 bbl/d of oil in

North Dakota at WTI less ~US$6.00/bbl for the remainder of 2020

Material focus areas

8

ESG

MATERIAL FOCUS AREAS

Reduce GHG emissions intensity through technological innovation & operational efficiency.

• Targeting a 10% reduction in GHG

emissions per BOE in 2020(1)

Greenhouse Gas E 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

Wat ater M Man anag agement Culture

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

• Promote an inclusive & supportive

workplace

• Measure employee engagement &

understand where gaps exist in culture alignment

Stakeh eholder er Engagem emen ent

Create positive & sustainable impacts in the communities in which we operate.

• Job creation
• Improved infrastructure
• Direct funding/community support

Healt lth an

and S Saf afety

We are committed to building a workplace where all injuries can be prevented.

• Ambition is zero incidents

Board C Constitution & C Culture

Active board oversight of corporate strategy, enterprise risk management and human capital management; empowers management to deliver

• n its corporate goals and objectives.
• Mix of essential skills, expertise & experience
• Independent with diversity of thought
• High level of engagement
• Champion diversity & inclusion
• Effective decision-making

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.

High return growth, free cash flow and low leverage

T R A C K R E C O R D

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

9

41

89%

• il

50

91%

• il

55

91%

• il

44 43 46 85 93 101 2017 2018 2019 Liquids Natural gas

16% 6%

3-year liquids production CAGR since 2016

High return oil growth

Production, MBOE/d

$316 $66 $160 $90 2017 2018 2019 Total

Foc

• cus on
• n f

free c cash flow

• w

Free cash flow(1), C$ millions

$29 $29 $28 $79 $179 2017 2018 2019 Dividends Share repurchases

Return of capital

C$ millions

>$300M 00MM

Cumulative free cash flow since 2017

~1 ~10%

Of shares outstanding repurchased since Q3 2018

0.6x 0.4x 0.6x 1.0x 0x 1x 2x 3x 2017 2018 2019 2H 2020

Low w finan ancial al leverag age

Net debt to adjusted funds flow ratio(1)

1.0x 0x

Leverage ratio at 2H 2020

North Dakota and Montana – Bakken / Three Forks

W 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 Divide Burke Richland Roosevelt Sheridan Dawson MONTANA NORTH DAKOTA

FORT BERTHOLD, ND

• Tier 1 acreage position
• Large remaining opportunity set
• Q2 2020 production: 42 Mboe/d (81% oil)

SLEEPING GIANT, MT

• Modest capital expenditures
• Low decline, strong free cash flow generator
• Q2 2020 production: 2 Mboe/d (86% 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 position

F 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.

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ERF BAKKEN POSITION – FORT BERTHOLD, ND

Light oi

• il p

prod

• duction
• n grow
• wth

Enerplus North Dakota production, Mboe/d(2) 45.6 10 20 30 40 50 2014 2015 2016 2017 2018 2019

FORT BERTHOLD INDIAN RESERVATION Mckenzie Dunn Mclean Mountrail

15% GROWTH

(2019 vs 2018)

• Track record of continued efficiency gains
• Solid execution YTD resulted in US$900K reduction in well costs compared to 2019(1)

Strong execution delivering capital efficiency gains

F 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

12

3,000 6,000 9,000 12,000 15,000 18,000 21,000 2 4 6 8 10 12 14 16 18 20 Depth (ft) Days

2017 Average 2018 Average 2019 Average 2020 Average Pacesetter

Dril illin ing e effic icie iency - cont ntinu nuing ng to d drill faster

Drilling days vs. depth (spud to rig release)(2)

4.9 6.7 8.8 10.5 2 4 6 8 10 12 2018 Average 2019 Average 2020 Average Pacesetter Stages/day

Complet etion ef efficien ency – more s stages es p per er d day

Stages per day

80 80%

IMPROVEMENT

(2020 vs 2018)

>6 days faster

(2020 vs 2017)

1) 2020 well costs expected to average US$6.7 million (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 growth

F 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.

13

Hig igh qualit ity d dril illin ing in inventory(1

(1)

Gross operated inventory locations

100 200 300 400 500 2020 Program Remaining Undrilled Inventory

Current Density: ~4 wells/DSU Ultimate Density: ~10 wells/DSU

Low E Existi ting Well l Density ty(2

(2)

• M. B

BAKKE KKEN TF TF 1 1 TF TF 2 2 TF TF 3 3 Certain deeper bench locations included in inventory in acreage where these zones are productive

Dev evel elopmen ent Plan p per er S Spacing Unit

22 o

• per

erated ed wells lls o

• nli

line ~410 o

• per

erated ed loc

• cation
• ns

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$6.7MM. 2) Well cost for a 2-mile lateral including drill, complete, tie-in and facilities costs.

14

Enerplus F Fort t Berth thold ld W Well ll P Performance

Cumulative oil production per well (Mbbl)

• 100

200 300 400 500 100 200 300 400 500 600 Producing days 2017 wells 2018 wells 2019 wells 2020 wells 2017 Avg 2018 Avg 2019 Avg 2020 Avg $8.1 $6.7 2017 2020 YTD

$1.4 M MIL ILLIO ION

WELL COST REDUCTION

Well e eco conomics cs(1)

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 W l Well C ll Costs ( (US$MM)(2

(2)

Bakken egress and price differential outlook

1) Source: NDIC, company estimates. 2) Production on chart is shown net of local refining demand. 3) Forecast rail volumes assume 275 mb/d continues to be contracted. Excess rail loading capacity is based on NDIC data, although active facilities are currently less than this.

15

Bak akken oil production & t tak akeaw away ay cap apac acity(1

(1)

Millions of bbl/d 0.0 0.4 0.8 1.2 1.6 2.0 2.4 2.8 Dec-13 Jun-14 Dec-14 Jun-15 Dec-15 Jun-16 Dec-16 Jun-17 Dec-17 Jun-18 Dec-18 Jun-19 Dec-19 Jun-20 Dec-20 Jun-21 Dec-21

Rail volumes(3) Pipelines (ex DAPL) DAPL Excess rail loading capacity(3)

• May 2020 production: 858 mb/d

(estimated 400 mb/d curtailed)

• Incremental rail available if needed:

− ~200 mb/d can be added in the near term − ~100 mb/d available per month thereafter up to nameplate capacity

Production(2

(2)

US US$5.00

PER BBL BELOW WTI (Assumes DAPL flows)

FULL-YEAR 2020 DIFFERENTIAL OUTLOOK

• $5.26
• $4.36

Q1 Q2 Q3 Q4

Ener erplus 2020 Bakken en Differ eren ential

US$/bbl compared to WTI

Expected 2020 average: -$5/bbl

• Non-operated position in Marcellus dry gas core

− 34,000 net acres − Q2 2020 production: 197 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 lower capital activity

Core acreage position in the Marcellus dry gas window

M 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.

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MARCELLUS POSITION – NE PENNSYLVANIA

Susquehanna Bradford Sullivan Lycoming Wyoming

Enerplus Marcellus produ duction

MMcf/d

195 198 208 227 206 2016 2017 2018 2019 2H 2020

Consistent free cash flow

Capex 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 basis

M A R C E L L U S M A R G I N

17

Mar arcellus cas ash m margin

US$/Mcf

$0 $0.29 $0 $0.51 $1 $1.06 $1 $1.31 $1 $1.00 $0 $0.62 $1.00 $1.02 $1.29 $1.34 $1.24 $1.10 $1.37 $0.93 $0.76 $0.43 $0.39 $0.45 $2.66 $2.46 $3.11 $3.08 $2.63 $2.17 $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 well 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 inventory

M A R C E L L U S W E L L R E S U L T S

1) Based on >180 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.

18

Marcel ellus wel ell p per erformance e 2017-20 2020 20

Average cumulative production per well(1)

Well e eco conomics cs(2

(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

65 w wells lls 71 w wells lls 48 w wells lls

Balanced Pricing Exposure

E 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

19

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

• n the improving

natural gas outlook

MARKET Leidy TZ6 Non-NY Gulf Coast Other

• $1.20
• $1.00
• $0.80
• $0.60
• $0.40
• $0.20

$0.00 $0.20 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 Q4 20

202 020e 0e p prici cing expo posure

% of expected Marcellus sales(1)

Ener erplus r rea ealized Marcel ellus diffe fferential(2

(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 11 10 10 10 9 8 12 12 12 11 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 production

C 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”.

20

CANADIAN WATERFLOODS

Stron

• ng c

cash flow

• w g

generation

• n

Net Operating Income minus Capex(2) (C$MM)

Low

• w decline oi
• il prod
• duction
• n

Mboe/d(2)

OIL IL GA GAS/NGL GL

>US$350 M MIL ILLIO ION

IN FREE CASH FLOW SINCE 2012

ANTE CREEK GILTEDGE CADOGAN MEDICINE HAT FREDA LAKE

Alberta British Columbia Saskatchewan

>$450 M MIL ILLIO ION

IN FREE CASH FLOW SINCE 2012

~$400 M MIL ILLIO ION

IN FREE CASH FLOW SINCE 2012 $0 $100 $200 $300 $400 $500 2012 2013 2014 2015 2016 2017 2018 2019

>$450 M MIL ILLIO ION

IN 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 field

E 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%.

21

DJ BASIN

2017/2018 -5 wells online (4 Codell, 1 Niobrara) 2019 -5 wells online (4 Codell, 1 Niobrara) 2020 - 2 wells online (2 Codell)

DENVER

WELD MORGAN ADAMS

WYOMING COLORADO

Returns and value focused

22

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 Q2 2020. Map does not include ~4.2 MBOE/d from other assets.

CDN DN W WATERFLOODS DS

6,300 BOE/d (94% oil)

BAKKEN

44,080 BOE/d (81% oil)

MARCELLU LLUS

197 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 volatile market
• Disciplined returns-based capital allocation

SUPPLEMENTAL INFORMATION

23

2020 guidance

24

Guidanc nce - Aug ugus ust 7, 2 2020 Capital Spending C$300MM Annual Average Total Production 88,000 - 90,000 BOE/day Annual Average Liquids 49,000 - 50,000 bbls/day Avg Royalty & Production Tax Rate(1) 26% Operating Expense $8.25/BOE Transportation Expense $4.15/BOE Cash G&A Expense $1.40/BOE Bakken – WTI Differential(2) US$(5.00)/bbl Marcellus – NYMEX Differential(2) US$(0.45)/Mcf

2020 guidance

Asset Net wells drilled Net wells onstream North Dakota 21 22.1 CDN Waterfloods 10 10.0 Marcellus 5 2.5 DJ Basin 5 1.8

Drilling & completion activity(3)

1) Based on % of gross sales, before transportation. 2) Excluding transportation costs. 3) Includes operated and non-operated activity.

7% 7% 7% 7% 8% 8% 8% 8%

• 1%

1% 5% 5% 8% 8% 3% 3% 10 10% 18 18% 23% 3%

• 8%

8% 12 12%

• 10%
• 5%

0% 5% 10% 15% 20% 25% 2016 2017 2018 2019

Track record of outsized returns vs. S&P 500

R 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.

25

Enerplus S&P 500 S&P 500 Energy

Retu turn on capita tal l employed(1

(1)

Enerplus goodwill impairment adjusted(2)

The Board of Directors

26

Karen E. Clarke-Whistler (Director since December 2018)

Corporate Governance & Nominating Committee Safety & Social Responsibility Committee

Ian an C. Dundas as President and CEO Judith D.

• D. Bu

Buie (Director since January 2020)

Audit & Risk Management Committee Reserves Committee

Rob

• bert B
• B. H

Hod

• dgins (Director since November 2007)

Audit & Risk Management Committee Compensation & Human Resources Committee Corporate Governance & Nominating Committee

Susan M. . MacKenzie (Director since July 2011)

Audit & Risk Management Committee Reserves Committee Safety & Social Responsibility Committee

Jef effrey ey W

• W. S

Sheet eets (Director since December 2017)

Audit & Risk Management Committee Compensation & Human Resources Committee Safety & Social Responsibility Committee

Shel eldon B. Steev eeves es (Director since June 2012)

Reserves Committee Safety & Social Responsibility Committee

Hila lary A. Foulk lkes (Director since February 2014) Board Chair (effective May 7, 2020) Elliott P Pew (Director since September 2010)

Previous Board Chair

ESG - Board oversight

27

Audit it & & R Ris isk Man anage agement t Committe ttee Compensati tion & & Human R Res esources Committe ttee Corporate te Gover ernance & & Nominati ting g Committe ttee Reserves es Committe ttee Safety ty & S Social Responsibility y Committe ttee

Board Committe ttees

Green eenhouse e Gas Emissions Water Man anag agement Culture Stak akeholde der Enga gage gement Healt lth &

& Saf afety

Boa

• ard C

Con

• nstitution
• n

& C Culture

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

Sustainability reporting

28

5 Y YEAR EARS

OF SUSTAINABILITY REPORTING

Summary of operational and financial metrics

29

2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Average 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 $ 27.85 $ 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 $ 1.72 $ 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 49,044 43,168 Natural 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 5,346 4,929 Natural Gas (MMcf/d) 263,506 261,310 256,995 260,591 260,453 259,837 258,568 287,000 282,360 285,537 278,451 262,913 235,579 Total (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 87,360 % Crude oil and natural gas liquids 48% 49% 54% 55% 56% 54% 51% 52% 56% 56% 54% 55% 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 $ 19.53 $ 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) $ (5.15) $ 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 $ 6.73 $ 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) $ (6.84) $ 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) $ (4.28) $ 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 $ 9.99 $ 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) $ (1.14) $ 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 $ (0.15) $ 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) $ (1.69) $ 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 $

• 1.81

$ 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 $ 8.82 $ 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

30

(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

Assumptions All amounts are stated in Canadian dollars unless otherwise specified. Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent This 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: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading, particular ly 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 the

• wellhead. 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 ona 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 Measures In this presentation, we use the terms “return on capital employed (ROCE)”, “adjusted funds flow", “net debt to adjusted funds flow ratio”, “netback”, “net operating income”, and "free cash flow" as measures to analyze leverage, liquidity and operating performance. These measures do 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 oper ating activities but before changes in non-cash operating working capital and asset retirement 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 12 months of adjusted funds flow. “Netback” and “net operating income” are calculated as oil and gas r evenues after deducting royalties, operating costs and transportation expenses. “Free cash flow” is calculated as “adjusted funds flow” less exploration and development capital spending (refer to “Non-GAAP Measures” in the Second 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 ter ms “ROCE”, “adjusted funds flow", “net debt to adjusted funds flow ratio”, “netback”, “net operating income”, and "free cash flow“ are useful supplemental 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 be comparable 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 and reconciliations to certain of these “Non-GAAP Measures” in the Second Quarter of 2020 and the 2019 Annual MD&A. Presentation of Production and Reserves Information Under U.S. GAAP, oil and gas s ales 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 pres ented on a gross basis before deduction of royalties. To remain comparable with our Canadian peer companies , the summar y results contained within this presentation presents our production and BOE measures on a before royalty “company interest “ basis. In addition, initial test results and production performance 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 ar e reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest. Unless otherwise specified, all res erves volumes in this presentation (and all information derived therefrom) are based on “gross reserves" using forecast prices and costs. “Gross reserves" (as defined in Na tional Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101")), being Enerplus’ working interest before deduction of any royalties. Our oil and gas reserves statement for the year ended December 31, 2019 includes complete disclosure of our oil and gas reserves and other oil and gasinformation 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 Commissionand is available on EDGAR at www.sec.gov. Readers are also urged 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-Place Discovered 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 our Canadian waterflood assets are estimates by internal qualified reserves evaluators, combined for all Canadian waterflood assets.

Advisories

31

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 "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies . Contingencies may include factors such as ultimate recovery rates, legal, environmental, political and r egulatory 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 ear ly intheir development for all of these r esources to be classified as res erves 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 r eserves . 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 ar e 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 gr eater 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 primar y 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

32

Investo tor R Relati tions Conta tacts ts

Dr Drew M Mair ir

Manager, Investor Relations 403-298-1707

Kri rista N Norl rlin

Senior Investor Relations Analyst 403-298-4304 Email: investorrelations@enerplus.com

Drilling Inventory Drilling locations associated with proved plus probable undeveloped reser ves have been evaluated or reviewed by Enerplus’ independent qualified reserves evaluators in accordance with the COGE Handbook. Drilling locations associated with unr isked “best estimate” economic contingent resources in “d evelopment pend ing” 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 res erves 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. READERS The 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 States or other foreign 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 (or, 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 us ed for reser ves evaluations, while the SEC mandates the use of an unweighted average of the closing 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 constant 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, contingent resources, see “Contingent Resources Estimates” above.