#1enerPlus TSX & NYSE: ERF INVESTOR UPDATE September 2022#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", "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: updated 2022 production and capital spending guidance; expected capital spending levels in 2022; expectations regarding 2022 and future shareholder returns, including payment of dividends and Enerplus' share repurchase program, the timing and amounts thereof and funding dividends and the share repurchase program from free cash flow; expectations regarding free cash flow generation and capital spending reinvestment rates; expected operating strategy in 2022 and expectations regarding our drilling program and well costs; 2022 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the expected effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; oil and natural gas prices and differentials and expectations regarding the market environment and our commodity risk management program in 2022; updated and existing 2022 Bakken and Marcellus differential guidance; expectations regarding realized oil and natural gas prices; expected operating, transportation and cash G&A expenses and production taxes and updated 2022 guidance with respect thereto; expectations regarding net debt and debt reduction; expectations regarding increases to dividends and timing thereof; and expectations regarding renewal of our normal course issuer bid, including timing and size thereof. The forward-looking information contained in this presentation reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; the continued operation of the Dakota Access Pipeline; 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; 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 COVID-19; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; 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 ability to fund increased dividend payments and the share purchase program from free cash flow as expected and discussed in this presentation; our ability to comply with our debt covenants; the availability of third party services; expected transportation expenses; the extent of our liabilities; and the availability of technology and process to achieve environmental targets. In addition, our 2022 guidance described in this presentation is based on: a WTI price of US$90.00/bbl, a NYMEX price of US$6.50/Mcf, a Bakken crude oil price of $+1.00/bbl above WTI, a Marcellus natural gas price differential of $(0.75)/Mcf below NYMEX and a CDN/USD exchange rate of 0.78. 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. Current conditions, economic and otherwise, render assumptions, although reasonable when made, subject to greater uncertainty. 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 environment, including from COVID-19, inflation and/or the Ukraine/Russia conflict and heightened geopolitical risks; 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; unanticipated operating results, results from our capital spending activities or production declines; legal proceedings or other events inhibiting or preventing operation of the Dakota Access Pipeline; 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; 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/or 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; 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 2022 interim MD&As, our annual information form for the year ended December 31, 2021, our 2021 annual MD&A and Form 40-F as at December 31, 2021). 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. 2#3Enerplus overview ■ Differentiated core Bakken drilling inventory (>decade) Compelling free cash flow generation (>20% FCF yield) ■Long track record of returning capital to shareholders ■Low financial leverage Deeply integrated approach to ESG CDN WATERFLOODS (Divestment process ongoing) BAKKEN Production by area (1) Production by product (1) Capital allocation (1) 65% 53% 28% 6% 1% ■Bakken Marcellus Canada ■ DJ 84% 38% Ο Ο 9% ■Crude Oil Natural Gas ■ NGL 3% 13% ■ Bakken ■ Marcellus Canada/DJ 1) Charts reflect 2022e production and capital allocation. enerPLUS MARCELLUS Dual listed: TSX & NYSE Market capitalization: US$3.5 billion 2022e production: 99,500 BOE/d (61% liquids) 3#4Key updates from Q2 2022 1 STRONG OPERATING RESULTS DRIVE PRODUCTION GUIDANCE INCREASE ■ 2022 guidance increased to 97.5-101.5 MBOE/d (+1.0 midpoint), despite announced asset sale in Canada ■ No change to capital spending guidance of $400-$440 million 2 TRACKING RECORD ANNUAL FREE CASH FLOW GENERATION (>20% FCF YIELD) ■ Generated free cash flow (1) of $327 million in the first half of 2022 ■ Increased 2022 full year free cash flow (1) estimate to approximately $800 million (2) 3 INCREASING RETURN OF CAPITAL TO SHAREHOLDERS ■ Repurchased 10% of public float between Aug 2021 - Jul 2022; renewed NCIB for another 10% in Aug 2022 ■ Increased quarterly dividend by 16% to $0.05/share ■ Increased return of capital to at least 60% of free cash flow starting in H2 2022, continuing in 2023 1) See Non-GAAP & Other Financial Measures in "Advisories". 2) Based on realized prices through July 2022 and then $90/bbl WTI and $6.50/Mcf NYMEX. enerPLUS 4#5Cumulative oil per well (Mbbls) enerPLUS Strong well performance & execution driving higher production forecast Enerplus' average North Dakota well performance (1) Average cumulative oil production per well 250 2019-2021 average (112 wells) 200 2022 YTD average (26 wells) 150 100 50 30 60 90 120 150 180 210 240 Producing days 270 300 330 360 2019-2021 wells 2022 wells 1) Includes all Enerplus operated wells since 2019. 2) Based on guidance midpoint. 2022 PRODUCTION GUIDANCE +1,500 BOE/d (vs initial guidance) (2) ■ Increased guidance despite storm impacts and announced Canadian divestment which have impacted production by -2,000 BOE/d Q3 LIQUIDS PRODUCTION GROWTH +15% (vs Q2) ■ Expecting robust second half 2022 volumes driven by an active development program and continued well outperformance 5#62022: disciplined plan, robust free cash flow generation Key figures 2022e free cash flow sensitivities (rest of year prices)(2)(3) TOTAL PRODUCTION 97,500-101,500 BOE/D 8% growth vs 2021 (1) $ CAPITAL SPENDING $ MILLIONS ال. REINVESTMENT RATE FREE CASH FLOW(2) $ MILLIONS $400-$440 -35% at $90/bbl WTI (3) $800 at $90/bbl WTI (3) Free cash flow ($ millions) $900 22% $850 $800 $750 $750 $700 23% $800 $650 2022e FCF $80 WTI 2022e FCF $90 WTI Free Cash Flow enerPLUS 24% 25% $850 20% 15% 10% 2022e FCF $100 WTI -Free Cash Flow Yield 1) 2022 growth of 8% is based on the guidance midpoint. 2022 growth is partially impacted by the timing of Enerplus' 2021 acquisitions. 2) See Non-GAAP & Other Financial Measures in "Advisories". 3) Based on realized prices through July 2022 and flat oil prices thereafter (assumes $6.50/Mcf NYMEX). Free cash flow yield is calculated as annual 2022 free cash flow divided by Enerplus' market capitalization on Sep 21, 2022. 6 Free cash flow yield#7Return of capital to shareholders enerPLUS 2022 free cash flow allocation oil price sensitivity (rest of year prices) (1) 2022 RETURN OF CAPITAL PLAN ■ Increased return of capital to at least 60% of free cash flow commencing in 2H 22 (from 50% previously) $ millions $1,000 $900 $850 $800 ■Increased minimum 2022 return of capital $800 $750 commitment to $425 million (from $350 million) $700 $393 Minimum $373 ■ Returns to be delivered through dividends and share $600 $353 return $325 $275 repurchases commitment: $425MM ■ Quarterly dividend increased by 16% to $0.05/share $400 ■ Minimum of $230 million in remaining cash returns in 2022 (Sep-Dec) $230 $230 $252 $282 $312 $200 $195 $195 $195 $195 $195 2023 RETURN OF CAPITAL PLAN ■ At least 60% of free cash flow $0 $70 WTI ■Capital returned to date $80 WTI $90 WTI ■Capital returns remaining $100 WTI $110 WTI ■Balance sheet Capital returns = Dividends + Share repurchases 7 1) Capital returned to date is inclusive of dividends and share repurchases through August 2022. Sensitivity uses $6.50/Mcf NYMEX. Allocation to balance sheet includes annual ARO spending.#8Bakken focused five-year outlook enerPLUS ■ Bakken focused five-year outlook expected to generate -$3bn of free cash flow (1) at $80/bbl WTI (1) ■ Annual liquids production growth rate of 3-5% (3) - Maintains sustainable base production decline rate Outlook excludes remaining Canadian assets due to ongoing divestment process Five-year outlook based on $80/bbl WTI, $4.00/Mcf NYMEX(1) Annual capital spending (2) Annual liquids production growth (3) -$500 million 3-5% Average reinvestment rate <50% Cumulative free cash flow (1) -$3 billion Five-year production and free cash flow outlook 5-Year free cash flow = 85% of current market cap at $80 WTI 125 Current market capitalization 100 75 Company production (Mboe/d) 25 25 50 50 $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 2026 2022 2023 2024 2025 (4) Bakken Marcellus -Cumulative free cash flow 1) See Non-GAAP & Other Financial Measures in "Advisories" 2022 is based on rest of year prices of $90/bbl WTI and $6.50/Mcf NYMEX. Years 2023-2026 are based on $80/bbl WTI and $4.00/Mcf NYMEX. 2) 2022 capital spending guidance is $400-$440MM. 2023-2026 projected at approximately $500MM. 3) 3-5% annual production growth is from 2023-2026 and is divestment adjusted for Canadian assets. 2022e growth is 8% based on the guidance midpoint. 4) Bakken production on chart includes volumes from the DJ Basin. 8 Cumulative free cash flow ( billions)#9ENVIRONMENTAL, SOCIAL & GOVERNANCE Material focus areas EMISSIONS MANAGEMENT (1)(2) 2021 Performance ■35% methane emissions intensity reduction ■25% total GHG emissions intensity reduction Targets: Methane intensity ■30% reduction by 2025 50% reduction by 2030 WATER MANAGEMENT (1) 2021 Performance ■31% freshwater reduction per well completion in North Dakota Target: Produced water use ■ 50% or greater produced water used in well completions by 2025 HEALTH & SAFETY (¹) 2021 Performance ▪ Zero lost time injuries ■116 consecutive incident free days Target: LTIF(3) reduction ▪ 25% LTIF reduction, on average, from 2020-2023 Target: GHG intensity ■35% reduction by 2030 Water Management Emissions Management enerPLUS Health & Safety ESG MATERIAL FOCUS AREAS Culture Community Engagement 1) 2021 performance is relative to a 2019 baseline. Emissions targets are relative to a 2021 baseline. Water and Health & 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. 9#10enerPLUS DIFFERENTIATED BAKKEN POSITION 10#11$0 WTI oil price ($/bbl) $10 $20 $30 $40 $50 $60 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 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. ய Little Knife & FBIR areas represent -85% of Enerplus' >10-year core inventory BAKKEN-US VIKING SHAUNAVON UINTA PRB BAKKEN-CDN DUVERNAY 11 enerPLUS#12enerPLUS Enerplus: substantial core acreage, large remaining opportunity set Lightly drilled acreage Drilling density: wells per DSU Acreage 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) UNIT DENSITY 0-2 3-5 6-9 Williams County Mckenzie County 10-13 14-20 EPLUS UNITS Outlines are Enerplus operated units Mountran Williams McKenzie Little Knife Low High Outlines are Enerplus operated units Mountrail FBIR Dunn 0 0 Indicative well NPVs NPV10 at $80 WTI (1) ($MM) $60 Approx. $4MM+ $50 Approx. $7MM+ $40 Approx. $12MM+ Murphy Creek Enerplus operated acreage Enerplus non-op acreage 1) Source: Drilling density based on internal mapping. Productivity mapping from Tudor, Pickering, Holt & Co. WTI breakeven analysis and drilling density based on internal research. Well NPVs at $80 & $100 WTI assume a total well cost of $6.5mm. Well NPVs at $60 WTI assume a total well cost of $6.0mm. 12#13Net drilling locations Deep drilling inventory supports sustainable outlook enerPLUS 1,000 900 800 700 250 600 670 110 500 FUTURE DRILLING LOCATIONS 400 IN CORE/ EXTENDED CORE (1) 300 200 100 45 2022 Onstreams (2) 560 North Dakota Inventory Inventory upsides ■Lower return locations that offer upside through stimulation advances, well cost improvements, sustained high oil prices Extended Core Periphery of established core ■Lower returns than Core, but exceeds returns threshold at midcycle prices ■ Primarily southern Dunn >Decade of Core drilling inventory (at development pace assumed in 5-year plan) Core ■ Established economic core of play ■ Well defined & de-risked ■ FBIR, northern Dunn, eastern Williams Additional drilling inventory in the Extended Core + Upside locations 1) See "Advisories - Drilling Inventory" for a reconciliation of undrilled locations between those associated with reserves and those not associated with any reserves. As at 1 Jan 2022. Includes operated and non-operated locations. 2) 2022 onstreams includes operated and non-operated wells. 13#14enerPLUS Bakken oil price strength supported by spare pipeline capacity. Bakken oil production & takeaway(1) Millions of bbl/d Oil price diffs Enerplus Bakken oil price differential vs WTI ($/bbl) I +$1.00/bbli I above WTI 2014 2015 2016 2017 -$3.72 2018 2019 2020 2021 2022 I 2023 -$2.15 -$3.78 -$3.98 -$5.39 -$7.46 -$9.44 -$12.94 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 2022 GUIDANCE Premium pricing vs WTI expected in 2022 2024 2025 2026 Basin not expected to test egress capacity. Expect in basin differentials to trade in $0-$2.00/bbl range below WTI Production forecast based on 50 rigs Wood Mackenzie Production forecast based on 30 rigs Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 14 1) Source: North Dakota Industrial Commission (NDIC), Company estimates, Wood Mackenzie. Production is shown net of local refining demand. 2) Forecast rail volumes assume 175 mb/d are contracted going forward.#15Why invest in Enerplus. ■ THE BAKKEN IS AN ADVANTAGED BASIN - 5,000 drilling locations at or below $50/bbl WTI (-7 years) - 10,000 drilling locations at or below $60/bbl WTI (-14 years) - 18,000 drilling locations at or below $70/bbl WTI (-25 years) - Significant egress: Bakken oil prices currently at a premium to WTI ENERPLUS IS A DIFFERENTIATED BAKKEN PLATFORM - Over a decade of core inventory based on 3-5% growth rate assumed in 5-year outlook Among the best drilling & completions execution and safety performance in the basin EXPOSURE TO STRONG NATURAL GAS PRICES THROUGH THE MARCELLUS - Strong free cash flow generation; attractive hedging in 2023 DISCIPLINED CAPITAL ALLOCATION Reinvestment rate of -35% in 2022, <50% in 2023-2026 assuming $80 WTI Forecasting -$800MM of free cash flow in 2022 (>20% FCF yield) based on $90 WTI Meaningful cash returns to shareholders ($425MM min. in 2022, 60% of FCF min. in 2023) Profitable and sustainable organic liquids production growth of 3-5% Low financial leverage with potential to be net debt free in 2023 enerPLUS 15#16APPENDIX enerPLUS 16#17enerPLUS Strong liquidity and low financial leverage Significant liquidity Liquidity position at June 30, 2022 ($ 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 $980 Track record of low financial leverage Net debt to adjusted funds flow ratio 3x Net debt as at June 30, 2022: $546 million Π 5-year track record of operating at or below 1x ND/AFF ratio annually Liquidity Cash + Undrawn Credit Facilities Revolving Credit Facilities Avg. interest rate: 3.85% (1) 2x 1.0x 0.9x 1x 0.6x 0.6x 0.5x 0.4x SENIOR NOTES $226 Avg. interest rate: 4.2% $121 $21 $21 $21 $81 $81 Ox 2022 2023 2024 2025 2026 2017 2018 2019 2020 2021 1H 2022 Senior Notes Revolving Credit Facilities Undrawn Credit Facilities + Cash 1) Drawn fees are expected to be approximately 3.85% based on an underlying 3-month LIBOR rate of 2.35%.. Drawn amount is net of unamortized debt issuance costs of $1.5MM. 17#182022 guidance enerPLUS $400 - $440 97.5 - 101.5 59.5-62.5 2022e capital allocation Williston Basin 2022 ANNUAL GUIDANCE Capital spending (US$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$/boe) Current tax expense (US$MM) Bakken oil price differential. vs WTI (US$/bbl) (1) 7% $10.00 $4.25 $1.20 2% -3% of adjusted funds flow before tax Marcellus natural gas price differential. vs NYMEX (US$/Mcf)(1) $+1.00 $(0.75) 1) Excluding transportation costs. 84% $400-$440 MILLION 13% 3% Marcellus Canada DJ Basin 18#19COMMODITY HEDGING SUMMARY Price risk management CRUDE OIL HEDGES (WTI)(1)(2)(3) Period Jul 1 Dec 31, 2022 Jan 1 - Jun 30, 2023 Volume (Mbbl/d) Jul 1 Dec 31, 2023 Jan 1 Dec 31, 2023(4) NATURAL GAS HEDGES (NYMEX)(2) Swaps Swaps (US$/bbl) Volume (Mbbl/d) Sold Put (US$/bbl) Collars Purchased Put (US$/bbl) Sold Call (US$/bbl) 17.0 $40.00 $50.00 $57.91 15.0 $61.67 $79.33 $114.31 5.0 $65.00 $85.00 $128.16 2.0 $5.00 $75.00 Swaps Collars Period Volume (Mcf/d) Swaps (US$/Mcf) Volume (Mcf/d) Sold Put (US$/Mcf) Purchased Put (US$/Mcf) Sold Call (US$/Mcf) Jul 1-Oct 31, 2022 40,000 $3.40 60,000 $3.77 $4.50 Nov 1, 2022 - Mar 31, 2023 120,000 $6.27 $18.17 Apr 1 Oct 31, 2023 50,000 $4.05 $7.00 enerPLUS 1) The total average deferred premium spent on our outstanding hedges is US$1.50/bbl from July 1, 2022 - December 31, 2022 and US$1.25/bbl from January 1, 2023 - December 31, 2023. 2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes. 3) Upon closing of the Bruin Acquisition, Bruin's outstanding crude oil contracts were recorded at a fair value liability of $76.4 million. At June 30, 2022, the remaining liability was $10.3 million on the Condensed Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Condensed Consolidated Statement of Income/(Loss) and the Condensed Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition. See Note 16 to the Interim Financial Statements for further details. 19 4) Contracts inherited from Bruin acquisition.#20BAKKEN CORE DRILLING INVENTORY FBIR Expected average well performance (1) Inventory Distribution Payout period and NPV10 at $60, $80, $100 per barrel WTI Net future drilling locations 300 WTI NPV10 $MM $100 $19 670 EXTENDED 250 $80 $13 200 150 50 50 Cumulative oil production (mbbls) 100 WTI $60 $7 CORE -110 locations $60 WTI $80 WTI $100 -- Payout: 6 months at $80 WTI 2 4 6 8 10 12 Month 14 16 18 20 22 24 Enerplus well $50 WTI breakeven well enerPLUS Mountrail Williams FBIR McKenzie Billings Dunn CORE -560 Development plan locations -10 wells per 1,280 ft. spacing unit 60% FBIR MB TF 1 TF 2 TF2 locations in select areas $60 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics at $80 & $100 WTI assume a total well cost of $6.5mm. Well economics at $60 WTI assume a total well cost of $6.0mm. 20#21BAKKEN CORE DRILLING INVENTORY Little Knife Expected average well performance (1) Inventory Distribution Payout period and NPV10 at $60, $80, $100 per barrel WTI Net future drilling locations 300 WTI NPV10 $MM $100 $19 250 $80 $13 $60 $7 670 EXTENDED CORE -110 locations 50 50 Cumulative oil production (mbbls) 200 150 100 $60 $80 WTI WTI $100 WTI Payout: 5 months at $80 WTI О 2 4 6 8 10 12 14 16 18 20 22 24 Month Enerplus well $50 WTI breakeven well 25% LITTLE KNIFE CORE -560 locations $60 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics at $80 & $100 WTI assume a total well cost of $6.5mm. Well economics at $60 WTI assume a total well cost of $6.0mm. enerPLUS Mountrail Williams Little Knife McKenzie Dunn Billings Development plan -6-9 wells per 1,280 ft. spacing unit MB TF 1 TF 2 21#22BAKKEN CORE DRILLING INVENTORY Eastern Williams Expected average well performance (1) Payout period at $60, $80, $100 per barrel WTI 300 WTI NPV10 $MM $100 $16 250 $80 $11 50 50 Cumulative oil production (mbbls) $60 $6 200 $60 WTI 150 $80 WTI $100 100 WTI --------- о Payout: 6 months at $80 WTI О 2 4 6 8 10 12 14 16 18 20 22 24 Month Enerplus well $50 WTI breakeven well Inventory Distribution Net future drilling locations 670 EXTENDED CORE -110 locations CORE -560 locations enerPLUS Mountrail Williams Eastern Williams 15% McKenzie E. WILLIAMS $60 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics at $80 & $100 WTI assume a total well cost of $6.5mm. Well economics at $60 WTI assume a total well cost of $6.0mm. Dunn Billings Development plan -5-6 wells per 1,280 ft. spacing unit MB TF 1 TF 2 22#23BAKKEN EXTENDED CORE DRILLING INVENTORY Murphy Creek Expected average well performance (1) Payout period at $60, $80, $100 per barrel WTI Inventory Distribution Net future drilling locations enerPLUS 50 50 Cumulative oil production (mbbls) 150 300 WTI NPV10 $MM $100 $11 250 $80 $6 $60 $2 Mountrail Williams 670 EXTENDED $60 CORE WTI -110 locations MURPHY CREEK 200 McKenzie $80 WTI Murphy Creek 150 $100 WTI Dunn Billings 100 CORE -560 locations Development plan -5-6 wells per 1,280 ft. spacing unit O 2 4 6 8 10 $50 WTI breakeven well Payout: 10 months at $80 WTI 12 14 16 18 20 22 24 Month Enerplus well $60 WTI breakeven well 1) See "Expected well performance" in "Advisories". Well economics at $80 & $100 WTI assume a total well cost of $6.5mm. Well economics at $60 WTI assume a total well cost of $6.0mm. MB TF 1 TF 2 23#24MARCELLUS OVERVIEW Core acreage position in the Marcellus dry gas window. ■ Non-operated position in Marcellus dry gas core 32,700 net acres 160-170 MMcf/d production (1) High quality exposure to robust natural gas prices Low cost structures Stable production, consistent free cash flow generation enerPLUS MARCELLUS POSITION - NE PENNSYLVANIA Bradford Susquehanna Wyoming Sullivan Lycoming Marcellus production & capital spending MMcf/d and $ millions Marcellus pricing exposure (Jul-Dec) Approx. % of natural gas sales 200 $60 18% ול+ ■Leidy 150 $25 $55 $40 100 ■TZ6 Non-NY $20 50 ■ Gulf Coast 154 158 160-170 $0.75/Mcf 2022e portfolio differential below 19% O $0 ■ Other 60% NYMEX 2020 2021 2022e Production Capital 3% 24 1) Enerplus production, net of royalties.#25Annual Excess Cash Flow() Marcellus robust excess cash flow generation Enerplus' Marcellus 2022 excess cash flow generation (1) Unhedged net operating income less capital spending sensitivity using flat H2 2022 NYMEX prices $400 $350 $300 $250 $200 $150 enerPLUS Natural gas commodity hedging contracts NYMEX $340 Jul 1, '22 - Oct 31, '22 Nov 1, '22 - Mar 31, '23 Apr 1, '23 - Oct 31, '23 $310 $280 Swaps Swaps 40,000 $245 Vol. (Mcf/d) $3.40 $215 $185 $100 $5.00 $6.00 $7.00 $8.00 $9.00 Collars Vol. (Mcf/d) 60,000 120,000 50,000 Puts $3.77 $6.27 $4.05 Calls $4.50 $18.17 $7.00 $10.00 H2 2022 NYMEX Benchmark Price (US$/Mcf) Enerplus Q2 2022 Marcellus production was 168 MMcf/d (net) 1) Excess cash flow is equal to net operating income less capital spending. Marcellus net operating income and capital spending in H1 2022 were $139 million and $31 million respectively. Marcellus capital spending in H2 2022 is estimated at approx. $25 million. Excludes impact of hedges. 25#26EMERGING OPPORTUNITY - DJ BASIN Northern extension of Wattenberg field enerPLUS -34,700 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 ■ Focused on enhancing well economics through further drilling & completion optimization 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 26#27Board of Directors enerPLUS Hilary A. Foulkes (Director since February 2014) Board Chair Mark A. Houser (Director since March 2022) Audit & Risk Management Committee Compensation & Human Resources Committee Reserves, Safety & Social Responsibility Committee Judith D. Buie (Director since January 2020) Audit & Risk Management Committee Corporate Governance & Nominating Committee Reserves, Safety & Social Responsibility Committee Karen E. Clarke-Whistler (Director since December 2018) Compensation & Human Resources Committee Corporate Governance & Nominating Committee Reserves, Safety & Social Responsibility Committee Susan M. MacKenzie (Director since July 2011) Compensation & Human Resources Committee (Chair) Reserves, Safety & Social Responsibility Committee Jeffrey W. Sheets (Director since December 2017) Audit & Risk Management Committee (Chair) Compensation & Human Resources Committee lan C. Dundas President and CEO Robert B. Hodgins (Director since November 2007) Compensation & Human Resources Committee Corporate Governance & Nominating Committee (Chair) Sheldon B. Steeves (Director since June 2012) Audit & Risk Management Committee Reserves, Safety & Social Responsibility Committee (Chair) 27#28Advisories 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. Previously, the Company presented production volumes on a "company interest" basis, which was calculated as its working interest share before deduction of royalties plus the Company's royalty interests. With these changes, production volumes presented by the Company on a "net" basis are expected to be lower than those presented historically. 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, 2021 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 2021 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, 2021, 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, 2021 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 2022 are 920 and comprise 316 2P undeveloped reserves locations, 284 best estimate contingent resources locations and 320 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. Payout times and NPVs are calculated assuming a $6.5MM capital well cost. 28#29Contacts Investor Relations Contacts Drew Mair Manager, Investor Relations & Corporate Planning 403-298-1707 Krista Norlin Sr. Investor Relations Analyst 403-298-4304 Email: [email protected] enerPLUS 29