#1enerPLUS TSX & NYSE: ERF INVESTOR UPDATE May 2023#2Forward looking information and statements enerPLUS This presentation 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", "intends", "plans", "budget", "strategy" 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: expected 2023 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials, including expected changes to such differentials year-over-year, and our commodity risk management program in 2023 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; operating, transportation and tax expenses; share repurchase plans and the amount of future cash returns to our shareholders by way of dividends and share repurchases; expected free cash flow generation and use thereof, including to fund share repurchases and dividends; the anticipated percentage of free cash flow planned to be returned to shareholders; he amount of future cash dividends that we may pay to our shareholders and the source of funds necessary in order to pay such dividends; execution of our remaining NCIB authorization and any future share repurchases and the anticipated timing thereof; expected reinvestment rates; capital spending levels and allocations in 2023 and impact thereof on our production levels and land holdings; our ESG initiatives, including Scope 1. and Scope 2 GHG emissions and methane emissions intensity, freshwater use reduction and health and safety targets; our anticipated progress towards our ESG initiatives, including timing and expected capital expenditures needed to achieve such targets; future environmental expenses; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with, renegotiate or renew our bank credit facilities and outstanding senior notes, as applicable; and our future acquisitions and dispositions. The forward-looking information contained in this presentation reflects several material factors and expectations and assumptions of Enerplus including, without limitation: the ability to fund our return of capital plans, including both dividends at the current level and the share repurchase program, from free cash flow as expected; that our common share trading price will be at levels, and that there will be no other alternatives, that, in each case, make share repurchases an appropriate and best strategic use of our free cash flow; that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current and anticipated commodity prices, differentials and cost assumptions; expectations regarding inflation; the general continuance of current or, where applicable, assumed industry conditions; the impact of inflation, weather conditions, storage fundamentals and expectations regarding the duration and overall impact of the continued conflict in Ukraine and the COVID-19 pandemic; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; expectations regarding our share price; 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 comply with our debt covenants; our ability to meet the targets associated with our bank credit facilities; the availability of third party services; the extent of our liabilities; estimates relating to our ESG emissions intensity; and the availability of technology and process to achieve environmental targets. In addition, our 2023 guidance contained in this presentation is based on the following: a WTI price of $80.00/bbl, a NYMEX price of $3.00/Mcf, a Bakken crude oil price differential of $0.50/bbl above WTI, a Marcellus natural gas price differential of $(0.75)/Mcf below NYMEX and a CDN/USD exchange rate of 0.74. 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 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 instability, or further deterioration, in global economic and market conditions, including from COVID-19 or similar events, inflation and/or Ukraine/Russia conflict and heightened geopolitical risk; decreases in commodity prices or volatility in commodity prices; changes in realized prices of Enerplus' products from those currently anticipated; changes in the demand for or supply of our products, including global energy demand and including as a result of ongoing disruptions to global supply chains; volatility in our common share trading price and free cash flow that could impact our planned share repurchases and dividend levels; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters and increased capital and operating costs resulting therefrom; inability to comply with applicable environmental government regulations or regulatory approvals and resulting compliance and enforcement actions; 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 facilities and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource 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 and third party service providers; failure to realize the anticipated benefits of the divestment of the Canadian assets; changes in law or government programs or policies in Canada or the United States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our 2023 interim reports and our annual MD&A, AIF and Form 40-F as at December 31, 2022). The forward-looking information contained in this presentation speaks only as of the date of this presentation. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws. Any forward-looking information contained herein are expressly qualified by this cautionary statement. The forward-looking information contained in this presentation speaks only as of the date of this presentation, and we do not 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. 2#3Enerplus overview enerPLUS Differentiated Bakken drilling inventory - Over a decade of high-quality inventory ■ Attractive free cash flow generation 16% free cash flow yield (1) ■ Competitive return of capital to shareholders At least 60% of 2023 free cash flow ■ Low financial leverage 0.1x net debt to adjusted funds flow ratio (¹) (at Mar 31, 2023) BAKKEN NORTH DAKOTA Dual listed: TSX & NYSE Market capitalization: US$3.0 billion MARCELLUS NE PENNSYLVANIA 2023e production: -95,500 BOE/d (62% liquids) Production by area and product(2) ■ Oil ■NGL ■Natural gas Bakken 65 MBOE/d Marcellus 28 MBOE/d Net operating income by area (2) Bakken Marcellus $1,240 Million $300 Million 3 1) See Non-GAAP & Other Financial Measures in "Advisories". 2023 free cash flow yield is based on $80 WTI and $3.00 NYMEX. Yield is calculated as annual 2023 free cash flow divided by Enerplus' market capitalization on May 2, 2023. 2) Charts reflect 2022 production and net operating income.#4FIVE YEAR TRACK RECORD High return growth, free cash flow and low leverage High return oil growth Production, MBOE/d 12% Liquids production CAGR Attractive free cash flow & return of capital $1.45 Bn Free cash flow (1) $866 MM Dividends + Share repurchases enerPLUS Low financial leverage throughout the cycle Net debt to adjusted funds flow ratio (1) 0.2x Leverage ratio at YE 2022 $1.45 Bn 100 92 81 75 75 39 73 36 38 35 32 32 56 40 44 41 2021 Natural gas 2018 2019 2020 Liquids 62 =2 $94.23 $64.77 $67.92 $57.03 WTI Oil price $39.40 $6.64 $3.84 $3.09 $2.63 $2.08 NYMEX Natural gas price $866 MM $730 1.0x 0.9x 0.6x 0.4x 0.2x $135 2022 Total free cash flow Total return of capital 2018 2019 2020 2021 2022 (2018-2022) (2018-2022) Share repurchases Dividends 4 1) See Non-GAAP & Other Financial Measures in "Advisories".#51 2 Key updates from Q1 2023 2023 PLAN IS ON TRACK - CAPITAL & PRODUCTION GUIDANCE UNCHANGED Q1 production was 97.7 Mboe/d, 6% higher y-o-y (19% higher on per share basis) STRONG FREE CASH FLOW DELIVERY Q1 free cash flow was $122 million (1) 3 COMPETITIVE RETURN OF CAPITAL TO SHAREHOLDERS Q1 dividends + share repurchases totaled $67 million; plan to return at least 60% of 2023 free cash flow to shareholders 4 CONTINUING TO STRENGTHEN BALANCE SHEET AND FINANCIAL FLEXIBILITY Reduced net debt by 32% from year-end 2022, ending Q1 2023 with net debt of $151 million 1) See Non-GAAP & Other Financial Measures in "Advisories". enerPLUS 5#6Q2 2023 completions setting up strong H2 oil growth enerPLUS ■ Q2 onstreams: 19 - 22 net operated wells including 3 - 5 refracs ■Includes two pads in Little Knife, one pad in FBIR Expect Q2 wells to set up strong oil growth in the second half of the year MONTANA NORTH DAKOTA 7-well pad (gross) Onstream timing: Q2 2023 Refracs Onstream timing: Q2 2023 Williams Williams Enerplus operated acreage Enerplus non-op acreage Billings McKenzie Little Knife Mountrail FBIR 8-well pad (gross) Onstream timing: Q2 2023 Dunn 6-well pad (gross) Onstream timing: Q2 2023 4-well pad (gross) Onstream in Q1 2023 Murphy Creek#72023 outlook TOTAL BOE/D PRODUCTION 93,000 98,000 Projecting 3-5% liquids growth (1) driven by North Dakota. Marcellus natural gas production expected to be -8% lower yoy due to reduced activity 2023 capital allocation DJ BASIN ■ Drilling & completions: 4 wells (46% WI) CAPITAL SPENDING $ $ MILLIONS $500 $550MM Capital allocation: 95% North Dakota, 2.5% Marcellus, 2.5% DJ Basin 95% 2.5% 2.5% $500-$550 MILLION enerPLUS NORTH DAKOTA ■2 drilling rigs: 55-60 wells (86% WI) Completions: 45-55 wells (87% WI) ■ Refracs ■ Non-op activity RETURN OF CAPITAL TO SHAREHOLDERS 60% of free cash flow minimum Expecting to return at least 60% of FCF through dividends and share repurchases. Remaining FCF to be allocated to the balance sheet MARCELLUS (NON-OP) ■Capital spending >70% lower compared to 2022 ■2-2.5 net drills 1-1.5 net completions North Dakota ■Marcellus ■ DJ Basin 1) Growth rate is adjusted for the sale of Canadian assets in the fourth quarter of 2022 with associated production of 6,400 BOE/d (78% liquids). 7#82023 free cash flow and return of capital 2023 expected free cash flow (1)(2) Based on $80/bbl WTI and $3.00/Mcf NYMEX ($ million) -$1,000 -$525 enerPLUS -16% FREE CASH FLOW YIELD -$475 $ FREE CASH FLOW PRIORITIES ■ Net debt reduction and return of capital ■ Return at least 60% of free cash flow to shareholders in 2023 through dividends and share repurchases ■ Returned - $67 million to shareholders in Q1 2023 ■ 3.3 million shares remaining under share repurchase authorization (NCIB); intend to renew in August 2023 for another 10% of shares outstanding(3) Estimated Adjusted fund flow 1) See Non-GAAP & Other Financial Measures in "Advisories". Estimated Capital spending Estimated Free cash flow 2) Capital spending is based on the midpoint of guidance ($500-$550MM). Free cash flow yield is calculated as annual 2023 free cash flow divided by Enerplus' market capitalization on May 2, 2023. 3) 3.3 million shares remaining under normal course issuer bid authorization as at May 3, 2023. NCIB can be renewed for up to 10% of the public float (within the meaning under the TSX rules). 8#9Meaningful share count reduction through repurchases ■ Share repurchases underpinned by the view that the intrinsic value of Enerplus is not adequately reflected in its trading value ■ Shares repurchases are enhancing per share growth Reduction to shares outstanding through repurchases Shares outstanding (millions) 257 enerPLUS -16% 257 255 244 242 235 227 217 215 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Adjusted net income (1) per share growth Production per share growth $200 $150 $ million $100 $0.18/share $50 $0 Q1 2021 Q1 2022 Adjusted net income 1) See Non-GAAP & Other Financial Measures in "Advisories". +260% $0.65/share 120 0.05 $0.75 +49% 0.041/share $0.60/share $0.60 100 0.034/share 0.04 $0.45 $0.30 $/share Mboe/d 0.027/share 80 0.03 60 0.02 $0.15 $0.00 40 0.01 Q1 2023 Q1 2021 Q1 2022 Q1 2023 Adjusted net income/share Production Production/share 9 Boe/share#10- Sustainable five-year outlook: 2023 2027 Production (Mboe/d)(1) 120 100 80 60 40 40 20 20 57 44 0 2022 Bakken enerPLUS OUTLOOK 2023 - 2027 based on $80 WTI & $4.00 NYMEX (3 $ Approximately $500-$550mm annual capital spending EFFICIENT OPERATING PLAN 3-5% annual liquids production growth MAINTAINS SUSTAINABLE BASE PRODUCTION DECLINE RATE 59 2023 Approximately 50% average reinvestment rate COMPETITIVE FREE CASH FLOW DELIVERY >10 years of drilling inventory UNDERPINNED BY HIGH RETURNING BAKKEN DRILLING LOCATIONS 2024 2025 2026 Marcellus Liquids production (mb/d)(1)(2) 1) 2022 production shown in chart and annual liquids production of 57 mb/d excludes production from the Canadian assets which were sold in Q4 2022. Bakken production on chart includes volumes from the DJ Basin. 2) 2023 production of 59 mb/d represents the guidance midpoint. 3) 2023 is based on $80 WTI & $3.00 NYMEX. 2027 10#11ENVIRONMENTAL, SOCIAL & GOVERNANCE Material focus areas EMISSIONS MANAGEMENT (1)(2) 2022e Performance ■9% methane emissions intensity reduction ■-16% total GHG emissions intensity reduction Targets: Methane intensity ■ 30% reduction by 2025 ■50% reduction by 2030 Target: GHG intensity ■35% reduction by 2030 WATER MANAGEMENT (1) 2022 Performance ■ 36% freshwater reduction per well completion in Fort Berthold Target: Produced water use ■ 50% or greater produced water used in well completions by 2025 HEALTH & SAFETY (¹) 2022 Performance ■ One LTIF(3) ■ Three-year average LTIF reduction of 80% (since 2020), relative to 2019 baseline Target: LTIF reduction ▪ 25% LTIF reduction, on average, from 2020-2023 Water Management Emissions Management enerPLUS Health & Safety ESG MATERIAL FOCUS AREAS Culture Community Engagement 1) 2022 emissions management performance targets are relative to a 2021 baseline; water management and health and safety targets are relative to a 2019 baseline. 2) Enerplus' GHG emissions reduction targets address scope 1 and 2 emissions. Scope 1 emissions are direct emissions from owned and operated facilities. Scope 2 emissions are indirect emissions from the generation of purchased energy for the Company's owned and operated facilities. 3) Lost Time Injury Frequency. 11#12Enerplus has a differentiated Bakken position enerPLUS#13WTI oil price ($/bbl) $60 $50 $40 $30 $20 $10 $0 40 Core Bakken is competitive with the best N.A. oil plays Third-party data: Breakeven WTI oil prices across North American oil plays (1)(2) Source: Enverus Intelligence Research Little Knife & FBIR represent the majority of Enerplus' Bakken drilling inventory 1) Breakeven prices represent the average WTI price at which wells generate a 10% IRR. Based on wells since 2018. 2) Based on oil plays developed with horizontal wells. UINTA VIKING CARDIUM DUVERNAY 13 enerPLUS#14Overview of Enerplus' Bakken position -236,000 NET ACRES 655 NET DRILLING LOCATIONS Core extended core Williams Williams -66,660 BOE/D Q1 2023 production 2 RIGS, -50 NET WELLS ONLINE 2023 operational plan +$0.50 PER BBL VS WTI 2023E oil price differential MONTANA NORTH DAKOTA McKenzie Little Knife Billings Enerplus operated acreage Enerplus non-op acreage enerPLUS Enerplus North Dakota Production MBOE/D 70 Mountrail 60 60 FBIR 50 38 40 30 20 Dunn Murphy Creek 10 57 65 2020 2021 2022 14#15enerPLUS Enerplus: tier 1 acreage position in the Bakken core Acreage largely in core & extended core Productivity: 6 month BOE/1K foot lateral Substantial sub-$50/bbl WTI inventory Contours based on breakeven WTI prices (10% IRR) Significant acreage in the established economic core of the play ■ Large remaining opportunity set with more than a decade of high-returning drilling inventory ■ Potential to extend economic inventory through technology advances, well cost improvements and sustained high oil prices ப Williams 0 Little McKenzie Knife Low High Outlines are Enerplus operated units 1) Source: Productivity mapping from Tudor, Pickering, Holt & Co. WTI breakeven analysis based on internal research. FBIR Dunn Mountre $60 $50 $40 Murphy Creek Enerplus operated acreage Enerplus non-op acreage 15#16Net remaining drilling locations (1) Deep drilling inventory supports sustainable outlook. enerPLUS 900 800 200 700 600 125 Upside ■Locations offer upside through stimulation advances, well cost improvements, Inventory distribution by area Core & Extended Core sustained high oil prices 500 655 Extended Core Periphery of established economic core ■Lower returns than Core, but 400 NET CORE & EXTENDED CORE exceed threshold at midcycle prices 300 REMAINING LOCATIONS 530 Core 200 100 Established economic core of the play "Well defined & de-risked -50 2023 Onstreams (2) North Dakota Inventory 15% 15% 25% 45% >Decade of high-quality drilling inventory (at development pace assumed in 5-year plan) FBIR E. Williams Little Knife Murphy Creek 1) See "Advisories - Drilling Inventory" for a reconciliation of undrilled locations between those associated with reserves and those not associated with any reserves. As at 1 Jan 2023. Includes operated and non-operated locations. 2) 2023 onstreams includes operated and non-operated wells. 16#17enerPLUS Bakken oil price strength supported by ample pipeline capacity Bakken oil production & takeaway(1) Millions of bbl/d Oil price diffs ----- Enerplus Bakken oil price differential vs WTI ($/bbl) +$0.50/bbl 2023 GUIDANCE $1.09 | I above WTI I 2014 2015 2016 2017 -$3.72 2018 -$3.78 2019 2020 2021 -$2.15 2022 2023 I -$3.98 -$5.39 -$7.46 -$9.44 -$12.94 Basin not expected to test egress capacity Pre-DAPL Significant rail utilization led to DAPL in service June 2017 Differentials strengthened due to increased pipeline egress 1.8 wider differentials 1.6 1.4 DAPL 1.2 1.0 Production 0.8 0.6 0.4 0.2 0.0 Jan-14 Jan-15 Jan-16 Jan-17 Pipelines (ex DAPL) Rail volumes (2) Jan-18 Jan-19 Jan-20 COVID/OPEC related oil price shock led to reduced basin production & increased spare pipeline capacity 1) Source: North Dakota Industrial Commission (NDIC), Company estimates, Wood Mackenzie. Production is shown net of local refining demand. 2) Forecast rail volumes assume 80 mb/d are contracted going forward. Production forecast based on 50 rigs Production forecast based on current rig count (41) Production forecast based on 30 rigs Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 17#18SUPPLEMENTARY INFORMATION 18#19NON-OPERATED MARCELLUS Core acreage position in the Marcellus dry gas window. Enerplus Marcellus capital spending enerPLUS MARCELLUS POSITION - NE PENNSYLVANIA $ Millions $31 $58 Enerplus Marcellus production MMcf/d 153 158 $57 -74% ■ Current NYMEX natural gas prices are over 50% lower than 2022 (1) $15 ■Marcellus drilling and completions activity down significantly y-o-y ■ Reduced activity 169 -8% -155 resulting in lower y-o-y production 2020 2021 2022 2023E 1) NYMEX natural gas prices averaged $6.64/Mcf in 2022 and prices year to date have averaged <$3.00/Mcf. Lycoming Bradford Susquehanna Wyoming Sullivan Marcellus pricing exposure (ROY) Approx. % of natural gas sales 18% ■Leidy ■TZ6 Non-NY ■Gulf Coast 60% -$0.75/Mcf Expected 2023 differential vs NYMEX 19% ■ Other 3% 19#20enerPLUS Strong liquidity and low financial leverage Significant liquidity Liquidity position at March 31, 2023 ($ millions) Enerplus was the first North American E&P to transition its principal credit facility to a Sustainability ESG Linked Credit Facility, incorporating ESG performance targets Track record of low financial leverage Net debt to adjusted funds flow ratio A Multi-year track record of operating at or below a 1x ND/AFF ratio, annually -$1.3Bn Liquidity Cash + Undrawn Credit Facilities SENIOR NOTES Avg. interest rate: 4.2%. 3x Net debt as at Mar 31, 2023: $150.6 million 2x 1.0x 1x 0.9x 0.6x 0.6x 0.4x 0.2x 0.1x $80.6 2023 $21.0 $21.0 $80.6 Ox 2024 2025 2026 2017 2018 2019 2020 2021 2022 Q1 2023 Undrawn Credit Facilities + Cash Senior Notes 20#21COMMODITY HEDGING SUMMARY Price risk management CRUDE OIL HEDGES (WTI)(1)(2) Swaps Period Volume (Mbbl/d) Brent-WTI Spread (US$/bbl) Volume (Mbbl/d) Sold Put (US$/bbl) Collars Purchased Put Sold Call (US$/bbl) (US$/bbl) Apr 1 Jun 30, 2023 10.0 $5.47 15.0 $61.67 $79.33 $114.31 Jul 1 Dec 31, 2023 Apr 1 Dec 31, 2023(3) 10.0 $5.47 5.0 $65.00 $85.00 $128.16 2.0 $5.00 $75.00 NATURAL GAS HEDGES (NYMEX)(2) Collars Period Volume (Mcf/d) Purchased Put (US$/Mcf) Apr 1 Oct 31, 2023 50,000 $4.05 Sold Call (US$/Mcf) $7.00 1) The total average deferred premium spent on our outstanding hedges is US$1.32/bbl from April 1, 2023 - December 31, 2023. and and $1.07/bbl from July 1, 2023 - December 31, 2023. 2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes. 3) Outstanding commodity derivative instruments acquired as part of the Bruin Acquisition. enerPLUS 21#222023 guidance 2023 ANNUAL GUIDANCE Capital spending (US$MM) Total production (Mboe/d) Liquids production (Mbbl/d) Average production tax rate (% of net sales, before transportation) Operating expense (US$/boe) Transportation expense (US$/boe) Cash G&A expense (US$/boe) Current tax expense Bakken oil price differential. vs WTI (US$/bbl)(1) Marcellus natural gas price differential. vs NYMEX (US$/Mcf)(1) 1) Excluding transportation costs. $500-$550 93-98 57-61 7-8% (previous 7%) $10.75-$11.75 $4.20 (previous $4.35) $1.35 5% -6% of adjusted funds flow before tax $+0.50 (previous $+0.75) $(0.75) enerPLUS 22#23BAKKEN DRILLING INVENTORY FBIR Expected average well performance (1) Payout period and NPV10 at $60, $80, $100 per barrel WTI 300 WTI NPV10 $MM $100 $18 250 $80 $12 50 50 Cumulative oil production (mbbls) 100 $60 $7 $60 WTI 200 $80 WTI $100 150 WTI Payout: 9 months Remaining Inventory Distribution 655 Net Core & Extended Core enerPLUS Mountrail Williams 45% FBIR FBIR Development plan -10 wells per 1,280 acre spacing unit MB at $80 WTI TF 1 0 2 4 6 8 10 12 14 Month 16 18 20 22 24 TF 2 Enerplus well $50 WTI breakeven well McKenzie Dunn Billings Three Forks second bench locations in select areas $60 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics assume well costs of $6.0mm at $50 WTI, $6.3mm at $60 WTI, $7.8mm at $80 WTI, and $8.0mm at $100 WTI. 23#24BAKKEN DRILLING INVENTORY Little Knife Expected average well performance (1) Payout period and NPV10 at $60, $80, $100 per barrel WTI 300 WTI NPV10 $MM $100 $18 250 $80 $12 50 50 Cumulative oil production (mbbls) 100 $60 $7 200 $80 $60 WTI WTI 150 $100 WTI о Remaining Inventory Distribution enerPLUS Mountrail Williams 655 Net Core & Extended Core Little Knife McKenzie 25% Little Dunn Billings Knife Development plan -6-9 wells per 1,280 acre spacing unit Payout: 8 months MB at $80 WTI TF 1 О 2 4 6 8 10 12 14 16 18 20 22 24 Month TF 2 Enerplus well $60 WTI breakeven well $50 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics assume well costs of $6.0mm at $50 WTI, $6.3mm at $60 WTI, $7.8mm at $80 WTI, and $8.0mm at $100 WTI. 24#25BAKKEN DRILLING INVENTORY Eastern Williams Expected average well performance (1) Payout period and NPV10 at $60, $80, $100 per barrel WTI 300 WTI NPV10 $MM $100 $15 250 $80 $10 50 50 Cumulative oil production (mbbls) 100 $60 $6 $60 200 $80 WTI $100 WTI 150 WTI о Remaining Inventory Distribution 15% E. Williams 655 enerPLUS Mountrail Williams Eastern Williams Net Core & Extended Core McKenzie Development plan -5-6 wells per 1,280 acre spacing unit Payout: 8 months at $80 WTI MB TF 1 О 2 4 6 8 10 12 14 Month 16 18 20 22 24 TF 2 Enerplus well $60 WTI breakeven well $50 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics assume well costs of $6.0mm at $50 WTI, $6.3mm at $60 WTI, $7.8mm at $80 WTI, and $8.0mm at $100 WTI. Dunn Billings 25 མ།#26BAKKEN DRILLING INVENTORY Murphy Creek Expected average well performance (1) Payout period and NPV10 at $60, $80, $100 per barrel WTI Remaining Inventory Distribution 15% Murphy Creek Cumulative oil production (mbbls) 300 WTI NPV10 $MM $100 $9 250 $80 $5 $60 $2 200 150 100 50 50 $60 WTI $80 WTI $100 WTI 655 enerPLUS Mountrail Williams Net Core & Extended Core McKenzie Murphy Creek Development plan -5-6 wells per 1,280 acre spacing unit Payout: 14 months at $80 WTI MB TF 1 0 2 4 6 8 10 12 14 16 18 20 22 24 Month TF 2 $50 WTI breakeven well Enerplus well $60 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics assume well costs of $6.0mm at $50 WTI, $6.3mm at $60 WTI, $7.8mm at $80 WTI, and $8.0mm at $100 WTI. Billings Dunn 26#27DJ BASIN Northern extension of Wattenberg field enerPLUS Enerplus holds -33,000 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 ■ Well results compare favorably to core DJ oil rates Continuing to advance project in 2023: 3 wells planned WYOMING COLORADO WELD 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) 2021 3 wells online (3 Codell) DENVER OIL WINDOW ADAMS MORGAN 27#28Board of Directors Hilary A. Foulkes (Director since February 2014) Board Chair lan C. Dundas President and CEO enerPLUS Sherri A. Brillon (Director since October 2022) Audit & Risk Management Committee Compensation & Human Resources Committee Judith D. Buie (Director since January 2020) Audit & Risk Management Committee Corporate Governance & Nominating Committee Reserves, Safety & Social Responsibility Committee Mark A. Houser (Director since March 2022) Audit & Risk Management Committee Compensation & Human Resources Committee Reserves, Safety & Social Responsibility Committee Jeffrey W. Sheets (Director since December 2017) Audit & Risk Management Committee (Chair) Compensation & Human Resources Committee Karen E. Clarke-Whistler (Director since December 2018) Compensation & Human Resources Committee Corporate Governance & Nominating Committee Reserves, Safety & Social Responsibility Committee Sheldon B. Steeves (Director since June 2012) Audit & Risk Management Committee Reserves, Safety & Social Responsibility Committee (Chair) 28#29Advisories Assumptions enerPLUS All amounts in this presentation are stated in U.S. dollars unless otherwise specified. All financial information in this presentation has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures". Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent This presentation contains references to "BOE" (barrels of oil equivalent), "MBOE" (one thousand barrels of oil equivalent), and "MMBOE" (one million barrels of oil equivalent). 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. BOE, MBOE and MMBOE 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 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 on a 6:1 basis may be misleading. Non-GAAP & Other Financial Measures This presentation includes references to certain non-GAAP financial measures and non-GAAP ratios used by the Company to evaluate its financial performance, financial position or cash flow. Non-GAAP financial measures are financial measures disclosed by a company that (a) depict historical or expected future financial performance, financial position or cash flow of a company, (b) with respect to their composition, exclude amounts that are included in, or include amounts that are excluded from, the composition of the most directly comparable financial measure disclosed in the primary financial statements of the company, (c) are not disclosed in the financial statements of the company and (d) are not a ratio, fraction, percentage or similar representation. Non-GAAP ratios are financial measures disclosed by a company that are in the form of a ratio, fraction, percentage or similar representation that has a non-GAAP financial measure as one or more of its components, and that are not disclosed in the financial statements of the company. These non-GAAP financial measures and non-GAAP ratios do not have standardized meanings or definitions as prescribed by U.S. GAAP and may not be comparable with the calculation of similar financial measures by other entities. Please see Management's Discussion & Analysis for the composition of each non-GAAP measure, the identified GAAP equivalency to the extent one exists, a reconciliation of the measure to the mostly directly comparable GAAP financial measure and details on the usefulness of the measure for the reader. These non-GAAP financial measures and non-GAAP ratios should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP. Please see "Non-GAAP Measures" in the latest MD&A for more detail. Other financial measures include supplementary financial measures and capital management measures. Supplementary financial measures are disclosed by a company that (a) are, or are intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of a company, (b) are not disclosed in the financial statements of the company, (c) are not non-GAAP financial measures, and (d) are not non-GAAP ratios. Capital management measures are financial measures disclosed by a company that (a) are intended to enable an individual to evaluate a company's objectives, policies and processes for managing the company's capital, (b) are not a component of a line item disclosed in the primary financial statements of the company, (c) are disclosed in the notes to the financial statements of the company, and (d) are not disclosed in the primary financial statements of the company. Please see "Other Financial Measures" in the latest MD&A Presentation of Production and Reserves Information All production volumes presented in this presentation are reported on a "net" basis (the Company's working interest share after deduction of royalty obligations, plus the Company's royalty interests), unless expressly indicated that it is being presented on a "gross" basis. All reserves information presented herein are reported in accordance with Canadian reserve evaluation standards under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("Canadian NI 51-101 Standards"), except certain reserves information effective December 31, 2022 in accordance with the provisions of the Financial Accounting Standards Board's ASC Topic 932 Extractive Activities - Oil and Gas, which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the U.S. Securities and Exchange Commission (collectively, the "U.S. Rules"), but does not necessarily include all of the disclosure required by the SEC disclosure standards set forth in Subpart 1200 of Regulation S-K (the "U.S. Standards"). The practice of preparing production and reserves data under the Canadian NI 51-101 Standards differs from the U.S. Rules and the presentation of production and reserves data under the Canadian Standards differs from presentation under the U.S. Standards. Please refer to our 2022 reserves news release for further information. All references to "liquids" in this presentation include light and medium crude oil, heavy oil and tight oil (all together referred to as "crude oil") and NGLS on a combined basis. All references to "natural gas" in this presentation include conventional natural gas and shale gas on a combined basis. Enerplus' oil and gas reserves statement for the year ended December 31, 2022, which will include complete disclosure of our oil and gas reserves and other oil and gas information prepared under the Canadian NI 51-101 Standards and also certain information about our oil and gas reserves prepared in accordance with the U.S. Rules, is contained within our Annual Information Form (AIF) for the year ended December 31, 2022 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 also urged to review the Management's Discussion & Analysis and financial statements filed on SEDAR and as part of our Form 40-F on EDGAR concurrently with this presentation for more complete disclosure on our operations. Drilling Inventory and Expected Well Performance Drilling 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 have been evaluated by Enerplus' independent qualified reserves evaluators, McDaniel & Associates Ltd in the case of North Dakota 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 Enerplus and have not been audited by Enerplus' independent qualified reserves evaluators. Existing Enerplus net locations in North Dakota as at 1 Jan 2023 are 855 and comprise 366 2P undeveloped reserves locations, 214 best estimate contingent resources locations and 275 unbooked future locations. The Enerplus expected well performance comes from analyzing historical well productivity within the geographic area outlined in the locator box. on the maps on the respective slides. The data set analyzed excludes wells completed before 2016 and the Enerplus expected well is an average of our future planned inventory. 29#30Contacts Investor Relations Contacts Drew Mair Sr. Manager, Investor Relations, Corporate Planning, Reserves 403-298-1707 Krista Norlin Sr. Investor Relations Analyst 403-298-4304 Email: [email protected] enerPLUS 30