#1enerPlus TSX & NYSE: ERF INVESTOR UPDATE November 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 zero- flaring alignment, 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 rest of year commodity prices: WTI price of $80.00/bbl, a NYMEX price of $3.00/Mcf, and a CDN/USD exchange rate of 0.72. 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 12% free cash flow yield (1) ■ Competitive return of capital to shareholders - 9% cash return yield (1) (based on -70% of 2023 free cash flow) ■ Low financial leverage 0.2x net debt to adjusted funds flow ratio (1) (at Sept 30, 2023) 1) See Non-GAAP & Other Financial Measures in "Advisories". 2023 free cash flow and cash return yields are based on fourth quarter commodity prices of $80/bbl. WTI and $3.00/Mcf NYMEX. FCF yield is calculated as 2023 free cash flow divided by Enerplus' market capitalization (Nov 1, 2023). Cash return yield is calculated as 2023 share repurchases and dividends divided by Enerplus' market capitalization (Nov 1, 2023). BAKKEN NORTH DAKOTA Dual listed: TSX & NYSE Market capitalization: US$3.5 billion 2023e production: -98,500 BOE/d (61% liquids) 2023E PRODUCTION BY PRODUCT 11% 0 38% 51% ■ Oil ■ Natural Gas NGL MARCELLUS NE PENNSYLVANIA 2023E PRODUCTION BY AREA 1% 26% 0 73% ■ Bakken ■ Marcellus Other 3#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 39 73 36 55 35 38 32 32 56 44 40 41 2018 2019 2020 2021 Liquids Natural gas 62 62 $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 (2018-2022) Total return of capital 2018 2019 2020 2021 2022 (2018-2022) Share repurchases 4 Dividends 1) See Non-GAAP & Other Financial Measures in "Advisories".#5Key updates from Q3 2023 1 INCREASED FULL-YEAR 2023 PRODUCTION GUIDANCE 2023 production guidance increased by 2,000 BOE/d at the midpoint due to strong well performance Guidance pointing to 7% y-o-y liquids production growth (adjusted for Canadian divestment in 2022) 2 CAPITAL SPENDING TRACKING BUDGET 2023 capital spending range tightened to $520-$540MM (from $510-$550MM previously) 3 ATTRACTIVE FREE CASH FLOW AND RETURN OF CAPITAL PROFILE IN Q4 2023 Anticipating strong free cash flow in Q4 as capital spending profile tapers ■ Returned -$200MM to shareholders Q1-Q3, with an estimated -$100MM to be returned in Q4 (1) 4 EXPECTING TO EXCEED 2030 GHG EMISSIONS INTENSITY REDUCTION TARGETS IN 2023 Projecting -40% reduction in scope 1 & 2 GHG emissions intensity in 2023 vs 2021 New 2030 targets set for scope 1 & 2 GHG and methane emissions 1) Based on fourth quarter 2023 commodity prices of $80/bbl WTI and $3.00/Mcf NYMEX. In the fourth quarter through Nov 1, Enerplus repurchased $41MM in stock. enerPLUS 5#6Billings Continued strong performance from Little Knife pads enerPLUS LITTLE KNIFE AREA - ENERPLUS ACREAGE Hay Draw Pad McKenzie Bice Pad Dunn Hay Draw Pad Cumulative Oil Production per well (Mbbls) Bice Pad (1) Cumulative Oil Production per well (Mbbls) 240 200 160 120 80 40 240 200 160 120 80 40 30 60 90 Normalized Production Day Enerplus Little Knife type well 120 150 180 Enerplus Little Knife type well 30 60 90 120 150 180 Normalized Production Day 6 1) Non-producing days removed. See "Expected well performance" in "Advisories".#7enerPLUS Differentiated well performance from Enerplus' core Bakken position Top 100 wells in North Dakota 2022-2023 based on peak month oil production Based on >1,400 wells brought on production in North Dakota since January 2022 Barrels of oil produced in peak month 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 FBIR OMELET 151-94-16B-21H FBIR SAUSAGE 151-94-16B-21H Little Knife Little Knife FBIR LK BICE 147-96-6-31-1H LK BICE 147-96-6-31-1H BACON 151-94-16B-21H Little Knife FBIR PANCAKE 151-94-16B-21H enerPlus Little Knife 13 of the top 100 wells are Enerplus operated 20 of the top 100 wells Enerplus operates or has a non-op interest in (Enerplus operated represents 5% of all new wells online in the basin since 2022) FBIR OSMIUM 147-93-17B-20H FBIR LEVIATHAN 151-94-27A-34-17T Little Knife FBIR FBIR Little Knife HAY DRAW 148-97-27-34-4H Little Knife Little Knife LEVIATHAN 151-94-27A-34-12T FBIR BOOMER 152-94-23CH FBIR HAY DRAW 148-97-27-34-5H Little Knife LK BICE 147-96-6-31-3H Little Knife 10,000 1) Source: North Dakota state data, Enverus, Enerplus. Enerplus operated well ☐ Enerplus non-operated interest in well 7#82023 outlook 2023 capital allocation TOTAL PRODUCTION 98,000 99,000 BOE/D Growing liquids volumes in North Dakota (60.5-61.5 Mbbl/d). Marcellus natural gas volumes expected to be -8% lower yoy due to reduced activity DJ BASIN ■ Drilling & onstreams: 3 wells (98% WI) $ CAPITAL SPENDING RETURN OF CAPITAL $520-$540 MILLION 95% of capital directed to North Dakota (1) -70% of 2023 free cash flow Returned 97% of FCF in H1. Planning to return at least 60% of FCF in H2 1) Based on fourth quarter commodity prices of $80/bbl WTI and $3.00/Mcf NYMEX. MARCELLUS (NON-OP) 1.3 net drills 0.9 net onstreams 95% 2% 3% $520-$540 MILLION enerPLUS ■North Dakota ■Marcellus DJ Basin NORTH DAKOTA ■ Op drills: 61 (85% WI) ■ Op onstreams: 46 (87% WI) ■ Refracs ■ Non-op activity 8#92023 free cash flow and return of capital 2023 estimated free cash flow and return of capital (1)(2)(3) Based on Q4 commodity prices of $80/bbl WTI and $3.00/Mcf NYMEX ($ million) -$960 Adjusted funds flow -$530 Capital spending -12% FREE CASH FLOW YIELD -9% CASH RETURN; YIELD -$430 Free cash flow -$300 Return of capital -$100MM expected in Q4 -$200MM through Q3 enerPLUS $ FREE CASH FLOW PRIORITIES ▪ Return of capital and strengthening balance sheet ■ Returned 97% of H1 2023 free cash flow to shareholders ■ Plan to return at least 60% of H2 2023 free cash flow to shareholders ■ Expected to result in -$300 million returned in 2023 (representing -70% of full-year free cash flow) 1) See Non-GAAP & Other Financial Measures in "Advisories". 2) Capital spending is based on the midpoint of guidance ($520-$540MM). 3) Free cash flow and cash return yields are based on Enerplus' market capitalization on Nov 1, 2023. Return of capital estimate based on H1 return of capital of $133MM and 60% of H2 FCF forecast.#10enerPLUS Meaningful reduction to share count and net debt over two years ■ Shares outstanding have been reduced by 18% over the last two years through repurchases Planning to continue active share repurchase program based on the view that the intrinsic value of the company is not adequately reflected in its trading value ■In addition to returning meaningful capital to shareholders, Enerplus has reduced net debt by over 70% Reduction to shares outstanding through repurchases Shares outstanding end of period (millions) 255 227 -18% 208 Q3 2021 Q3 2021 Q3 2023 Net debt ($ millions) $826 -74% $391 $212 Q3 2021 Q3 2022 Q3 2023 10#11Sustainable five-year outlook: 2023 2027 - 120 100 Production (Mboe/d)(1) 80 60 60 40 20 20 о 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 SUSTAINABLE PRODUCTION DECLINE RATE & INVENTORY DURATION 61 57 2022 Bakken 2023e Marcellus Approximately 50% average reinvestment rate COMPETITIVE FREE CASH FLOW DELIVERY >10 years of drilling inventory UNDERPINNED BY HIGH RETURNING BAKKEN DRILLING LOCATIONS 2024 2025 Liquids production (mb/d)(1)(2) 2026 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 61 mb/d represents the guidance midpoint. 3) 2023 is based on fourth quarter commodity prices of $80/bbl WTI & $3.00/Mcf NYMEX. 2027 11#12GHG EMISSIONS MANAGEMENT Significant progress reducing emissions. enerPLUS ■ Enerplus expects to exceed previous 2030 targets in 2023; revised 2030 targets to reflect better than anticipated performance Scope 1 Emissions Intensity Reduction kg CO₂e / BOE Scope 1 & 2 Emissions Intensity Reduction kg CO₂e / BOE Methane Emissions Intensity Reduction kg CH₁ / BOE 29.4 2023E PERFORMANCE ■ -40% from 2021 -40% ■ -55% from 2019 -17.0 -60% from 2023 7.0 33.1 2023E PERFORMANCE 2023E PERFORMANCE 0.068 ■ -40% from 2021 ■ -45% from 2021 -40% -45% ■ -55% from 2019 ■ -65% from 2019 ----- -19.5 -30% from 2023 -0.036 13.0 2021 2023E 2030 2021 2023E Target 2030 Revised Target 2021 2023E -45% from 2023 0.02 2030 Revised Target 12#13GHG EMISSIONS MANAGEMENT GHG emissions reduction initiatives North Dakota Emissions Sources (2022) 13% Oil Tanks ...... 4% Other 1% - Pneumatics 10% Stationary Combustion 2022 North Dakota Scope 1 Emissions 34% Stationary Combustion 48% Associated Gas Flaring Flaring & methane initiatives ■ Broad installation of vapor recovery units ■ Improved operational and midstream planning ■ Enhanced metering & measurement Expect to have removed all reportable pneumatic devices (1) by end of 2023 ■Installing flare cameras to limit flare downtime Engines & power initiatives ■ Onsite power load optimization ■ Piloting innovative technologies to capture emissions and utilize geothermal energy Participation in an electrification project to expand the power grid to the southern area of Fort Berthold Indian Reservation ■ Dual fuel drilling rig (with industrial battery technology, EPA tier 4 engines) 17% Pneumatics 66% Associated Gas Flaring 4% Other 3% **** Oil Tanks 2022 North Dakota Methane Emissions 1) All remaining pneumatic devices were acquired via 2021 transactions. enerPLUS لكا Endorsing the World Bank Zero Routine Flaring by 2030 initiative Established flare intensity target of <2%/Mcf of natural gas produced by 2026 enerPLUS#14NORTH DAKOTA SUPPLEMENTARY ASSET DETAIL enerPLUS#15WTI 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 15 enerPLUS#16Overview of Enerplus' Bakken position 236,000 NET ACRES 655 NET DRILLING LOCATIONS Core extended core -77,702 BOE/D Q3 2023 production 68% crude oil 16% NGL 16% natural gas MONTANA NORTH DAKOTA Williams Williams McKenzie Little Knife 2 RIGS, -50 NET WELLS ONLINE (1) 2023 operational plan Oil price $0.25/BBL BELOW WTI 2023E Bakken crude oil avg price differential Billings Enerplus operated acreage Enerplus non-op acreage 1) 2023 onstreams includes operated and non-operated wells. 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 16#17■ enerPLUS Enerplus: tier 1 acreage position in the Bakken core Contours based on breakeven WTI prices (10% IRR)(1) 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 1) WTI breakeven analysis based on internal analysis. $60 $50 $40 Enerplus operated acreage Enerplus non-op acreage 17#18Net remaining drilling locations (1) Deep drilling inventory supports sustainable outlook. enerPLUS 900 800 200 700 600 125 Upside ■Locations offer upside through stimulation advances, well cost improvements, Inventory distribution by area Core & Extended Core sustained high oil prices 500 655 Extended Core Periphery of established economic core ■Lower returns than Core, but 400 NET CORE & EXTENDED CORE exceed threshold at midcycle prices 300 REMAINING LOCATIONS 530 Core 200 100 Established economic core of the play "Well defined & de-risked -50 2023 Onstreams (2) North Dakota Inventory 15% 15% 25% 45% >Decade of high-quality drilling inventory (at development pace assumed in 5-year plan) FBIR E. Williams Little Knife Murphy Creek 1) See "Advisories - Drilling Inventory" for a reconciliation of undrilled locations between those associated with reserves and those not associated with any reserves. As at 1 Jan 2023. Includes operated and non-operated locations. 2) 2023 onstreams includes operated and non-operated wells. 18#19enerPLUS Bakken oil price strength supported by ample pipeline capacity Enerplus average Bakken oil price differential vs WTI ($/bbl) Bakken oil production & takeaway (1) Millions of bbl/d Oil price diffs $1.09 2014 2015 2016 2017 -$3.72 2018 -$3.78 2019 2020 2021 -$2.15 2022 2023E -$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 COVID/OPEC related oil price shock led to reduced basin production & increased spare pipeline capacity 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 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. 2023 Guidance $0.25/bbl below WTI Basin not expected to test egress capacity Production forecast based on 50 rigs Production forecast based on 40 rigs Production forecast based on 30 rigs Current rig count = 33 (October 2023) Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 19#20BAKKEN 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, $7.7mm at $80 WTI, and $8.0mm at $100 WTI. 20#21BAKKEN 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, $7.7mm at $80 WTI, and $8.0mm at $100 WTI. 21#22BAKKEN 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, $7.7mm at $80 WTI, and $8.0mm at $100 WTI. Dunn Billings 22#23BAKKEN 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, $7.7mm at $80 WTI, and $8.0mm at $100 WTI. Billings Dunn 23#24SUPPLEMENTARY INFORMATION 24#25enerPLUS Strong liquidity and low financial leverage Significant liquidity Liquidity position at Sept 30, 2023 ($ 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 Multi-year track record of operating at or below a 1x ND/AFF ratio, annually -$1.2Bn Cash + Undrawn Credit Facilities 3x Net debt as at Sept 30, 2023: $212 million SENIOR NOTES Avg. interest rate: 4.1% CREDIT FACILITIES Avg. interest rate: 6.6% $81 Liquidity 2024 Undrawn Credit Facilities + Cash Senior Notes 2x 1.0x 1x 0.9x 0.6x 0.6x 0.4x 0.2x 0.2x $52 $85 $21 $21 Ox 2017 2018 2019 2020 2021 2022 Sept 2025 2026 30, 2023 Credit Facilities - Drawn Amount 1) Drawn fees on the $1.3B credit facilities are expected to be approximately 6.6% based on an underlying 1-month SOFR rate of 5.42%. Drawn amount of $135.7mm is net of unamortized debt issuance costs of $2.0MM. 25#26COMMODITY HEDGING SUMMARY Price risk management CRUDE OIL HEDGES (WTI)(1)(2) Swaps Collars Period Volume (Mbbl/d) Brent-WTI Spread (US$/bbl) Volume (Mbbl/d) Sold Put (US$/bbl) Purchased Put (US$/bbl) Sold Call (US$/bbl) Oct 1 Dec 31, 2023 10.0 $5.47 10.0 $65.00 $81.00 $111.58 Oct 1 Dec 31, 2023(3) 2.0 $5.00 $75.00 Jan 1, 2024 - Jun 30, 2024 5.0 $65.00 $77.00 $95.00 NATURAL GAS HEDGES (NYMEX)(2) Collars Period Volume (Mcf/d) Purchased Put (US$/Mcf) Oct 1 Oct 31, 2023 50,000 $4.05 Sold Call (US$/Mcf) $7.00 1) Contracts as at Nov 1, 2023. The total average deferred premium spent on our outstanding crude oil contracts is $1.19/bbl from Oct 1, 2023 - Jun 30, 2024. 2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes. 3) Outstanding commodity derivative instruments acquired as part of the Company's acquisition of Bruin E&P Holdco, LLC completed in 2021. enerPLUS 26#272023 guidance 2023 GUIDANCE Capital spending (US$MM) Total production (Mboe/d) Liquids production (Mbbls/d) Q4 production (Mboe/d) Q4 liquids production (Mbbls/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)() Marcellus natural gas price differential vs last day NYMEX (US$/Mcf)(1) 1) Excluding transportation costs. $520-$540 (previous $510-$550) 98 99 (previous 94.5 - 98.5) 60.5 61.5 (previous 58.5 - 61.5) 95-99 60.5-64.5 8% $10.75 $11.00 (previous $10.75 - $11.50) $4.05 (previous $4.20) $1.35 3-4% of adjusted funds flow before tax $(0.25) (previous at Par) $(0.85) (previous $(0.75)) enerPLUS 27#28NON-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% ■ NYMEX natural gas prices are materially lower in 2023 vs 2022 $15 ■Marcellus drilling and completions activity down significantly y-o-y ■ Reduced activity 169 -8% resulting in lower -155 y-o-y production 2020 2021 2022 2023E Lycoming Bradford Susquehanna Wyoming Sullivan Marcellus pricing exposure (ROY) Approx. % of natural gas sales 18% ■Leidy -$0.85/Mcf ■TZ6 Non-NY 2023e differential ■Gulf Coast vs last day NYMEX 19% 60% ■ Other 3% 28#29ENVIRONMENTAL, SOCIAL & GOVERNANCE Material focus areas Health & Safety Water Management Culture ESG Emissions Management MATERIAL FOCUS AREAS enerPLUS Approach Integrate key ESG factors that can reduce risk and support business resilience ■ Clear, consistent disclosure of ESG information allows stakeholders to make informed decisions Integration Identify focus areas that could materially impact company value Establish goals and targets relative to our material focus areas Integrate objectives Oversight Senior leadership team is deeply involved in the identification of material focus areas and, in conjunction with the Board of Directors, in setting objectives and targets and targets throughout the organization " Focus areas are integrated into enerPLUS Community Engagement ESG REPORT 2023 enterprise risk management 9 YEARS OF ESG & SUSTAINABILITY REPORTING DISCLOSURE & REPORTING FRAMEWORK AXPC " CDP GRI 11 IPIECA SASB " TCFD 29#30Board 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 (Chair) Reserves, Safety & Social Responsibility Committee Sherri A. Brillon (Director since October 2022) Audit & Risk Management Committee Compensation & Human Resources Committee Ward Polzin (Director since June 2023) Audit & Risk Management 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 (Chair) Reserves, Safety & Social Responsibility Committee Jeffrey W. Sheets (Director since December 2017) Audit & Risk Management Committee (Chair). Compensation & Human Resources Committee Sheldon B. Steeves (Director since June 2012) Audit & Risk Management Committee Reserves, Safety & Social Responsibility Committee (Chair) lan C. Dundas President and CEO 30 |#31Advisories 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.sedarplus.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. The data set analyzed excludes wells completed before 2016 and the Enerplus expected well is an average of our future planned inventory. 31#32Contacts 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