Corporate Presentation August 2017

Corporate Presentation August 2017

Forward-Looking Information and Statements This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", guidance, "ongoing", "may", "will", "project", "should", "believe", "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, on the entire company basis and on asset-level basis, as applicable: expected average and fourth quarter production volumes in 2017 and the anticipated production mix; targeted 2019 production compound annual growth and Enerplus expected source of funding thereof; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; our drilling program, including future development locations and plans, the results from our drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; future efficiencies and reserves and production growth; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating costs; capital spending levels in 2017 along with its components and their impact on our production levels and land holdings; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, and our tax pools and the time at which we may pay Canadian cash taxes; net operating income and future adjusted funds flow levels, including on per share and debt adjusted basis; future debt and working capital levels and net debt-to-adjusted funds flow ratios and adjusted payout ratios, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; and future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom; and the amount of future cash dividends that we may pay to our shareholders. The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: continued low commodity prices environment or further decline of commodity prices; changes in realized prices for Enerplus products; changes in the demand for or supply of Enerplus' products; 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, incentive programs or other regulatory matters; changes in capital plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of Enerplus' oil and gas reserves and contingent resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; constraints on, or unavailability of, adequate pipeline and transportation capacity; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our Annual Information Form and Form 40-F, described below and under Risk Factors and Risk Management in our MD&A for the year ended December 31, 2016). The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions made by Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the availability of third party services; and the extent of our liabilities. Our updated 2017 guidance herein is based on the following prices for the second half of 2017: a WTI price of US$50.00/bbl, NYMEX gas price of US$3.00/Mcf, and AECO gas price of $2.40/GJ, and US/CDN exchange rate of 1.30. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The purpose of our adjusted funds flow disclosure, as well as the net operating income disclosure from both the Corporation s Marcellus and Canadian Waterflood assets is to assist readers in understanding Enerplus expected and targeted financial results, and this information may not be appropriate for other purposes. Certain measures used in this presentation do not have a standardized meaning under United States GAAP ( U.S. GAAP ). Please refer to Non-GAAP measures in the Advisories. The forward-looking information contained in this presentation speaks only as of the date of this presentation, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws. 1

Enerplus Overview TSX, NYSE ERF Market Cap Net Debt (1) Enterprise Value C$2.7 billion C$0.4 billion C$3.1 billion Canadian Oil Waterfloods Production (2) : 11,900 BOE/d Key Messages Top quartile capital efficiencies High quality drilling inventory Williston Basin Production (2) : 32,240 BOE/d Marcellus (NE PA) Production (2) : 205 MMcf/d Strong balance sheet Focused on profitable, sustainable growth 1) Net debt is the principal amount of long-term debt and includes working capital. As at June 30, 2017 2) Second quarter 2017 average production. Waterflood production adjusted for divestments that closed in Q2 2017 2

Production Growth Three Year Outlook Disciplined, Profitable Growth ~30% total company production growth through 2019 (1) ~70% liquids growth (1) >85% of capital allocated to crude oil projects Annual Production Outlook MBOE/day 115 100 ~10% CAGR (1) North Dakota production to approximately double Growth within cash flow Capital spending and dividends to be approximately balanced with cash flow at US$50/bbl WTI and US$3.00/Mcf NYMEX 85 70 (1) 2016 2017E 2018E 2019E Annual Liquids Production Outlook MBBL/day 75 ~20% CAGR (1) 60 45 1) 2016 production does not include volumes for assets divested during 2016 and YTD 2017 30 (1) 2016 2017E 2018E 2019E 3

2017 Capital Program Driving Crude Oil Production Growth Budget focused on high rate-of-return North Dakota crude oil growth Strong liquids growth entry to exit (~25%) 2017 Capital Allocation C$ millions Forecast Liquids Production Mbbl/day North Dakota Marcellus 50 Q4 Liquids Guidance 43 48 Mbbl/d C$330MM Two operated rigs ~26 net wells drilled (1) ~28 net wells onstream (1) C$60MM ~8 net wells drilled ~6 net wells onstream 45 40 35 C$450 MILLION CDN Waterfloods C$60MM Waterflood expansion & optimization Polymer injection 30 25 20 15 10 5 0 Q1 2017 Q2 2017 Q4 2017E 1) Operated wells only 4

Margin Improvement Lower Costs and Tighter Differentials Driving Margin Expansion Strong cost focus and divestment of higher cost assets driving cost structure reductions Narrowing Bakken and Marcellus differentials supporting significant pricing improvement Cost Structure Reduction C$/BOE $15.79 $15.50 $2.22 $2.09 $1.65 $1.71 $2.69 $2.95 $13.53 $13.65 $1.75 $1.87 $1.33 $1.33 $3.14 $3.88 ~20% REDUCTION $12.43 $1.53 $1.30 $3.72 Improved Realized Pricing Enerplus Natural Gas Price Differential vs. NYMEX (US$/Mcf) ($0.84) ($0.98) ($0.91) ($0.57) Enerplus Oil Price Differential vs. WTI (US$/bbl) ($0.59) ~30% IMPROVEMENT $9.23 $8.75 $7.31 $6.57 $5.88 ($10.79) ($9.38) ($8.37) ($7.08) 2014 2015 2016 Q1 2017 Q2 2017 ($14.71) ~50% IMPROVEMENT Opex Transportation Interest G&A 2014 2015 2016 Q1 2017 Q2 2017 5

Cash Netback (1) (C$/BOE) WTI Crude Oil Price (US$/bbl) Step Change in Cash Flow Generation Structural Cost and Pricing Improvements Delivering Strong Cash Flow 2017 cash netback (before hedging) is equivalent to Q4 2014 when WTI was >$70/bbl and NYMEX >$4/Mcf $25 WTI $73.15 $80 $20 $15 $14.61 WTI $48.80 WTI $43.32 ~$25/bbl reduction in WTI yet equivalent cash netback WTI $51.92 $14.79 $14.58 WTI $48.29 $70 $60 $50 $40 $10 $30 $5 $5.94 $6.58 $20 $10 $0 Q4 2014 2015 2016 Q1 2017 Q2 2017 Cash Netback, before hedging (C$/boe) Hedging Gain (C$/boe) WTI $0 1) Cash netback is equal to revenue less royalties, production taxes, operating costs, transportation costs, G&A costs and interest costs. 6

Balance Sheet & Liquidity Position Significant Financial Strength Strong liquidity position: no significant debt maturities until 2020 Net debt reduced by 75% since 2015 (1) Cash balance: $385 MM, Senior notes outstanding: $693 MM (2), undrawn $800 MM bank credit facility Prudent Leverage Management Senior Notes Repayment Schedule (2)(3) Net Debt / Trailing 12-Months Adjusted Funds Flow (4) C$ millions $131 2.5x $106 $106 $105 $105 1.4x 1.3x 1.2x 0.9x 0.7x $29 $57 $27 $27 2013 2014 2015 2016 Q1 2017 Q2 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1) Net debt at June 30, 2017 consists of total debt of $693 MM, cash of $385 MM. 75% reduction since December 31, 2015. 2) Senior notes outstanding at June 30, 2017 comprise CDN$30MM and US$511MM. U.S. dollar denominated notes translated at June 30, 2017 FX rate of USD/CDN 1.2977 3) Senior notes are rated NAIC 2 (investment grade) by the National Association of Insurance Commissioners and rank equally with the bank credit facility; weighted average interest rate of 4.8% (at June 30, 2017). 4) Net debt to adjusted funds flow ratio is a non-gaap measure. Please refer to the Non-GAAP measures in the Q2 2017 MD&A and Advisories for further detail. 7

ERF Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 Peer 18 Peer 19 Peer 20 Peer 21 Cdn Peer Avg Peer 22 Peer 23 Peer 24 Peer 25 Peer 26 Peer 27 Peer 28 Peer 29 Peer 30 Peer 31 Peer 32 US Peer Avg Peer 33 Peer 34 Peer 35 Peer 36 Peer 37 Peer 38 Peer 39 Peer 40 Balance Sheet Strength Financial Position Among the Strongest In Peer Group Significant financial flexibility Enerplus is committed to maintaining a strong balance sheet Net Debt / 2017E Cash Flow (1) 14.0x 12.0x 10.0x 8.0x 6.0x 4.0x 2.0x 0.6x 2.2x 3.7x 0.0x 1) Source: BMO July 14, 2017 comps at strip pricing 2) US Peers: CPE, CRZO, DNR, ECR, EPE, FANG, LPI, MTDR, OAS, PDCE, PE, RSPP, SM, SWN, SN, WLL, WPX. CDN Peers: AAV, ARX, ATH, BIR, BNE, BNP, BTE, CPG, CR, KEL, CONA, NVA, PEY, PPY, OBE, RRX, SPE, TET, TOG, TOU, TVE, VET, VII, WCP 8

Hedging Summary Protecting Cash Flow Crude Oil Hedging Summary (1)(2) bbls/day; WTI US$/bbl Natural Gas Hedging Summary (1)(2)(3) Mcf/day; NYMEX US$/Mcf % HEDGED (3) 72% 58% 72% 15% 15% % HEDGED (3) 25% 22,000 80,000 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 - $60.33 x $50.61 x $39.62 $61.99 x $53.04 x $42.83 $53.50 $61.29 x $52.56 x $42.63 $70.00 x $56.00 x $45.00 $53.73 $53.73 $53.73 $66.18 x $54.69 x $43.75 2H 2017 1H 2018 2H 2018 Q1 2019 Q2 - Q4 2019 WTI Swaps WTI 3 Way Collars 60,000 40,000 20,000 0 $3.41 x $2.75 x $2.06 2017 NYMEX 3 Way Collars 1) As of July 31, 2017 2) 3-way collars are comprised of a sold put, a purchased put and a sold call 3) Percentages are based on 2017 forecast crude and natural gas volumes respectively, net of royalties 9

Continued Capital Efficiency Improvement Generated Strong F&D and Capital Efficiencies Consistently delivering top quartile F&D costs driven by North Dakota and the Marcellus Capital efficiencies expected to improve through 2017 ~80% of capital allocation to crude oil projects from 2014 2017 Finding & Development Costs (1) C$/BOE Q4 Capital Efficiencies (2) C$/BOE/day $15 $13.37 $30,000 $11.90 $25,000 $25,000 $10 $9.80 $8.44 $20,000 $20,000 $15,000 $16,000 $15,000 $5 $4.77 $4.82 $10,000 $5,000 $0 2014 2015 2016 $0 2014 2015 2016 2017E PDP F&D 2P F&D 1) At December 31, 2016. PDP is proved developed producing reserves. 2P is proved plus probable reserves. 2P F&D includes future development costs. See Advisories 2) Q4 capital efficiency is calculated as capital expenditures from the fourth quarter of the previous year up to and including the third quarter of the current year, divided by the change in production from the fourth quarter of the previous year to the fourth quarter of the current year, net of base decline. 10

Williston Basin North Dakota & Montana - Light Oil Assets Fort Berthold, ND Acreage concentrated in the core Low well density vs surrounding acreage Two operated rigs in 2017 Q2 2017 production: ~28,050 BOE/d Sleeping Giant (Elm Coulee) Fort Berthold Sleeping Giant, MT Q2 2017 production: ~4,190 BOE/d Minimal capital expenditures; low decline strong free cash flow generator Enerplus leases 11

Fort Berthold, North Dakota Bakken / Three Forks Tier 1 Acreage Position Key Details Net Acreage (operated) 65,500 acres 2P Reserves (1) 139 MMBOE Contingent Resources (2) 120 MMBOE Future Drilling Locations (3) 524 Gross (457 Net) Operated drilling rigs 2 Acreage concentrated in Bakken core Lightly drilled; ~2 wells/dsu Current full development assumes ~10 wells/dsu Basin leading well performance Enerplus leases Continuing to optimize development; well density testing and completion modifications ongoing 1) Gross working interest at December 31, 2016 2) Unrisked best estimate economic contingent resources as at December 31, 2016. See the 2016 Annual Information Form Appendix A for more detail 3) Future drilling locations as at December 31, 2016. Net locations includes 88 proved plus probable undeveloped reserves locations, 215 best estimate contingent resources locations, and 154 unbooked future locations. Unbooked future locations are internal estimates and have not been audited by external evaluators. See Advisories 12

Depth (ft) Fort Berthold Efficiencies Focused on Continuous Improvement Total well cost (10MM lbs. of proppant) down ~40% since 2014 Cost performance driven by efficiencies and supply chain savings Sustainable costs with ~75% of 2017 North Dakota capital costs protected from escalation Drilling Efficiency Gains Long Lateral Wells Drilling Days vs Depth (ft) Spud to Rig Release Total Well Cost Reduction Two-Mile Lateral: Drill, Complete & Facilities (US$MM) 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 22,000 Days 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 2014 Long Lat Avg 2015 Long Lat Avg 2016 Long Lat Avg 2017 Long Lat Avg Pacesetter $13.0 2014 Well Cost ($1.9) 1) Includes drill, complete, surface facilities, including three months water flowback and the installation of artificial lift in the first year ($2.8) ~40% REDUCTION ($0.5) $7.8 Drill Complete Facilities Current Well Cost (1) 13

Enerplus Completion Evolution High Intensity Completions Driving Strong Well Results Continued focus on completions optimization Completion design guided by economic returns and capital efficiency Enerplus Well Performance Cumulative barrels of oil Enerplus Avg. Proppant Intensity vs ND Peers (1) Proppant volume (lbs/lateral ft.) 220,000 200,000 2014-17 completions (60 wells) 2013 completions (20 wells) 1,200 Enerplus Average 180,000 2012 completions (23 wells) 1,000 160,000 140,000 Increasing proppant intensity 800 120,000 100,000 600 80,000 60,000 400 40,000 20,000 0 0 50 100 150 200 250 300 200 - Upper Quartile (Peer wells) Lower Quartile (Peer wells) Median (Peer wells) 2012 2013 2014 2015 2016 2017 Days 1) Peer data based on IHS. Peers comprise: Continental, EOG, Hess, Marathon, Newfield, Oasis, QEP, Statoil, WPX, Whiting, XTO 14

North Dakota Well Performance Top Quartile Well Performance Enerplus core acreage position and completion design are delivering among the best well performance in the basin Cumulative Oil Production per 1,000 Lateral Feet Barrels of oil, all wells since 2014 through May 2017 80,000 70,000 60,000 Industry Bakken/Three Forks wells ERF Bakken wells ERF Three Forks wells 50,000 40,000 30,000 20,000 10,000 - - 200 400 600 800 1,000 1,200 Days On Production 1) Data based on IHS from January 1, 2014 through May 2017 2) Chart excludes the EOG operated Riverview 102-32H well with cumulative production per 1,000 ft. of 116,500 through 731 days on production 15

Fort Berthold Type Curves and Well Economics Fort Berthold Type Curves Barrels of oil per day 1,800 1,600 1,400 1,200 1,000 800 600 400 200 80% 70% 60% 50% 40% 30% 20% 10% 0% 0 1,200 MBO Type Curve (1,400 MBOE) 900 MBO Type Curve (1,050 MBOE) 0 5 10 15 20 25 30 35 40 45 50 Months Cumulative % of Recoverable Oil Produced by Year 1 2 3 4 5 6 7 8 9 10 Year Well / Economic Assumptions Lateral length 10,000 ft. Proppant loading 1,000 lbs/lateral ft Drilling & completions cost US$6.7MM Facilities cost US$1.1MM WTI price (flat) US$50/bbl Differential to WTI (1) -US$4.50/bbl NYMEX price (flat) US$3.00/Mcf Type Curve Production & Economics Oil (MBO) 1,200 900 Oil Equivalent (MBOE) 1,400 1,050 30 Day Cum. Oil Prod (bbls) 48,118 36,089 1 st Year Cum. Oil Prod (bbls) 267,121 200,341 IRR Pretax (%) 63% 32% Payout (Years) 1.6 2.6 Breakeven WTI Price (US$/bbl) (2) $33.50 $39.20 1) Basis differential to WTI: -US$4.50/bbl for 2017 & 2018; -US$5.00/bbl for 2019; and US$6.00/bbl for 2020 & 2021 2) Breakeven based on 10% rate of return 16

Fort Berthold Well Density and Inventory Significant Resource Opportunity Current development plan based on ~10 wells per drilling spacing unit (DSU) Well spacing and completions design tests ongoing to optimize development Maximize economic returns and recoverable resources per DSU Development Plan per DSU (~10 wells/dsu) Fort Berthold Inventory WELL LOCATIONS (1) ~524 GROSS ~457 NET Middle Bakken Three Forks 1 Three Forks 2 Three Forks 3 Well location Well lease line location Certain deeper bench locations included in inventory in acreage where these zones are productive 1 Mile 1) Future drilling locations as at December 31, 2016. Net locations includes 88 proved plus probable undeveloped reserves locations, 215 best estimate contingent resources locations, and 154 unbooked future locations. Unbooked future locations are internal estimates and have not been audited by external evaluators. See Advisories 17

Fort Berthold Significant Running Room Low existing well density Large remaining opportunity set is well defined Gross Locations (1) Wells Drilled & Future Drilling Locations 800 33% of remaining locations 700 600 46% of remaining locations 500 400 300 200 100 Lightly drilled (~2 wells/dsu) 21% of remaining locations ~4 wells/ DSU ~7 wells/ DSU ~10 wells/ DSU 0 Wells Drilled 2P (P+PUDs) Locations Contingent Resource Locations Internally Identified Locations Total Wells Drilled + Undrilled Locations 1) Wells drilled and future drilling locations as at December 31, 2016. Gross locations includes 109 proved plus probable undeveloped reserves locations, 239 best estimate development pending contingent resources locations, and 176 internally identified future locations. Internally identified future locations are internal estimates and have not been audited by external evaluators. See Advisories 2) DSU is a drilling spacing unit. Well locations per DSU is a simple average and may vary by specific DSU 18

Industry Bakken Oil Production & Takeaway Capacity Pipeline takeaway and refining exceeds existing basin production by over 200,000 bbls/day Forecasting approximately US($3.50)/bbl differential to WTI for H2 2017 North Dakota Production and Takeaway Capacity Mbbl/d 1,400 1,200 Pipe & Refining Capacity North Dakota Production Basin now structurally long pipe Enerplus Bakken Crude Oil Discount to WTI (US$/bbl) 2014 2015 2016 H1 2017 H2 2017E 1,000 Rail required to clear the basin 800 600 Dakota Access pipeline commenced operations June 2017 -$5.49 -$3.50 400 -$7.46 200 -$9.44 0 H1 2014 H2 2014 H1 2015 H2 2015 H1 2016 H2 2016 H1 2017 H2 2017 H1 2018 H2 2018 H1 2019 H2 2019 -$12.94 >US$9.00/bbl IMPROVEMENT 1) Source: North Dakota Pipeline Authority and PIRA 19

Marcellus Core Acreage Position in NE Pennsylvania Key Details Net Acreage 2P Reserves (1) Contingent Resources (2) Future Net Drilling Locations (3) 39,000 acres 895 Bcf 837 Bcf 129 Net Acreage located in NE PA dry gas core Significant low cost, highly productive drilling inventory Enerplus leases Enhanced completions driving strong well performance 10 to 15 Bcf type curves (5,500 ft lateral) 1) Gross working interest at December 31, 2016 2) Unrisked best estimate economic contingent resources at December 31, 2016. See the 2016 Annual Information Form Appendix A for more detail 3) Future net drilling locations as at December 31, 2016. Includes 32 proved plus probable undeveloped reserves locations and 97 best estimate contingent resources locations. See Advisories 20

Marcellus Well Results Continued Strong Performance Well performance continuing to track at or above type curve expectations Average Cumulative Gas Production (1)(2) Bcf 10 9 8 Lat. Lateral Length length Less < Than 4,000 4,000' Lat. Lateral Length length greater > 4,000 than 4,000' but < 6,000 and less than 6,000' Lat. Lateral Length length greater > 6,000 than 6,000' 12 7 6 5 4 36 30 76 23 70 9 15 Bcf Type Curve 10 Bcf Type Curve 3 2 77 36 77 33 32 30 6 1 33 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 Months on Production 1) Based on wells on production since January 2014 2) Numbers on curves indicate gross wells 21

Marcellus Type Curves & Well Economics Marcellus Type Curves MMcf of gas per day 12 10 8 15 Bcf Type Curve 10 Bcf Type Curve Well / Economic Assumptions Lateral Length Proppant Loading Well Cost 5,500 ft. 1,600 lbs/lateral ft. US$5.5MM 6 NYMEX flat price US$3.00/Mcf 4 Differential to NYMEX (2017) -US$0.75/Mcf (1) 2 Transport cost (2017) US$0.18/Mcf 0 0 5 10 15 20 25 30 35 40 45 50 Months Cumulative % of Recoverable Gas Produced by Year 70% 60% 50% 40% 30% 20% Type Curve Production & Economics (1) Gas (Bcf) 15 10 30 Day Cum. Gas Prod (Bcf) 0.25 0.33 1 st Year Cum. Gas Prod (Bcf) 2.8 2.0 IRR Pretax (%) 36% 17% Payout (Years) 2.5 4.4 Breakeven NYMEX Price (US$/Mcf) (2) $2.30 $2.71 10% 0% 1 2 3 4 5 6 7 8 9 10 Year 1) Basis differentials to NYMEX: 2017 -US$0.75/Mcf, 2018 -US$0.40/Mcf and 2019 & beyond -US$0.30/Mcf, 2) Breakeven based on a 10% rate of return 22

Marcellus Pricing Improvement and Increasing Free Cash Flow Generation Regional natural gas prices had been reconnecting to NYMEX Delays announced in late May to Rover pipeline project weakened regional gas prices Expect pricing to improve once Rover and other H2 2017 pipeline projects are completed Henry Hub vs. Marcellus Improving Spot Price Correlation (US$/Mcf) $4.00 Rover delay announced Enerplus Capital Spending & Net Operating Income C$ millions $120 $3.00 $2.00 $1.00 Improving Correlation $0.00 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 $100 $80 $60 $40 $20 $0 ~70% POTENTIAL INCREASE IN FREE CASH FLOW 2016 2017E Henry Hub Cash Transco Leidy Cash Capital Net Operating Income 1) Free cash flow is a non-gaap measure and is calculated as net operating income (netback before hedging) less capital expenditures. Net operating income & netback are also non-gaap measures. See the June 30, 2017 MD&A regarding non-gaap measure components used to calculate free cash flow. 2017E net operating income based on guidance of US$3.00/Mcf NYMEX and basis differential of US$0.75/Mcf (plus transportation costs of US$0.18/Mcf) below NYMEX and US/CDN exchange rate of 1.30 23

Atlantic Bridge - Q4 2017 Connecticut Exp. - Q4 2017 Susquehanna W Exp. - Q4 2017 Triad Exp. 300 - Q4 2017 DTI New Market Q4 2017 Northern Access Q2 2018 Atlantic Sunrise Q3 2018 Constitution Q4 2018 Empire N. Exp. Q4 2018 Penn East Q2 2019 NE Pennsylvania Pipeline Projects Significant Takeaway Expansion Planned Large slate of projects planned to further debottleneck NE PA production NE Pennsylvania Pipeline Projects MMcf/day 16,000 2018 ~3.1 Bcf/day 2019 1.0 Bcf/day 14,000 12,000 2017 ~0.6 Bcf/day 1,700 650 300 1,000 ~14,000 10,000 ~9,000 133 72 145 180 112 497 8,000 6,000 4,000 2,000 0 Estimated current NE PA production ~4.7 Bcf/d INCREMENTAL CAPACITY 1) Source: ERF estimates, Bentek Energy, company reports. 2) PennEast project expected in service mid 2019 (internal estimate). 24

Marcellus Marketing Portfolio Marcellus Marketing Portfolio MMcf/d 250 200 ERF Q2 2017 Gross Marcellus Production Expected Pricing Exposure (1)(2) Based on Q2 2017 production volumes TZ6 Non-NY Other Gulf Coast Leidy 150 100 50 - Monthly/Daily sales at Leidy Firm Sales Firm Transportation Capacity Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 PennEast (1) Estimated Marcellus Portfolio Differential and Transport Cost US$/Mcf 2017E 2018E 2019E Average portfolio differential ($0.75) ($0.40) ($0.30) Firm transport cost ($0.18) ($0.18) ($0.21) 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% ($1.13) $0.00 ($0.09) ($0.81) ($0.40) ($0.25) ($0.09) ($0.66) ($0.30) $0.07 ($0.09) ($0.47) Differential + transport ($0.93) ($0.58) ($0.51) 0% H2 2017 2018 2019 1) PennEast project expected in service mid 2019 (internal estimate). TZ6 volume reflects commitments once PennEast is in service 2) Data labels indicate discount to NYMEX (US$/Mcf) based on internal estimates and July 31, 2017 forward curves 25

Canadian Waterflood Portfolio Large Oil in Place, Low Decline, Stable Production Key Details Discovered OOIP (1) (bbls) 0.9 billion 2P Reserves (2) (MMBOE) 51 Contingent Resources (3) (MMBOE) 34 ANTE CREEK ( ) Average Decline Rate (%) 14 High netback, free cash flow generating assets Activity focused on waterflood optimization and expansion, and ongoing polymer flooding 1) Estimated by internal qualified reserves evaluators, excluding OOIP associated with the divestment of Brooks, which is expected to close March 2017. See Advisories 2) Gross working interest at December 31, 2016, adjusted to exclude the divestment of Brooks, which is expected to close March 2017 3) Unrisked best estimate economic contingent resources at December 31, 2016. See the 2016 Annual Information Form Appendix A for more detail 26

Canadian Waterflood Portfolio Cost Structure Enhancements Supporting Strong Cash Flow Generation Cost focus, efficiencies, and portfolio optimization are driving improved cost structure Modest capital to maintain production levels, with strong free cash flow Operating Expense C$/BOE Capital Spending & Net Operating Income C$ millions $20 $16 $18.00 $15.00 $7.00/BOE IMPROVEMENT $140 $120 $100 STRONG FREE CASH FLOW GENERATION $12 $12.00 $11.00 $80 $60 $8 $40 $20 $4 2014 2015 2016 H1 2017 $0 2016 2017E Capital Net Operating Income 1) Free cash flow is a non-gaap measure and is calculated as net operating income (netback before hedging) less capital expenditures. Net operating income (netback) are also non-gaap measures. See the June 30, 2017 MD&A regarding non-gaap measure components used to calculate free cash flow. 2017E net operating income based on US$50/bbl WTI, average differential to WTI of -US$11.00 and US/CDN exchange rate of 1.30 27

Why Invest in Enerplus Focused on profitable, sustainable growth Strong balance sheet High quality asset base Top quartile capital efficiencies Margin expansion Attractive valuation 28

Supplemental Information

Reducing Leverage and Abandonment Liabilities Net debt reduced 75% since YE 2015 (1) Senior notes outstanding: $693 MM (2) and cash of $385 MM Divestment activity has reduced ARO by 62% since YE 2014 Debt, net of cash C$ millions Asset Retirement Obligation (ARO) Estimated present value, C$ millions $1,400 $1,200 $1,216 $350 $300 $289 $1,000 $250 $800 $200 $600 $400 $200 $0 YE 2015 75% REDUCTION $308 30-Jun-17 $150 $100 $50 $0 YE 2014 62% REDUCTION $111 30-Jun-17 1) Net debt at June 30, 2017 is net of cash of $385.1 million 2) Senior notes outstanding at June 30, 2017 comprise $CDN30MM and US$541MM. US dollar denominated notes translated at June 30 FX rate of USD/CDN 1.2977 30

2017 Guidance (1) Capital Spending Annual Average Production Q4 Average Production Annual Average Liquids Production Q4 Average Liquids Production C$450 million 84,000 86,000 BOE/d 86,000 91,000 BOE/d 39,500 41,500 bbls/d 43,000 48,000 bbls/d Average Royalty & Production Tax Rate (2) 24% Operating Expense Transportation Expense Cash G&A Expense Bakken WTI Differential (3) Marcellus NYMEX Differential (3) C$6.40/BOE C$3.90/BOE C$1.75/BOE US($4.50)/bbl US($0.75)/Mcf 1) 2017 guidance assumptions: WTI US$50.00/bbl, NYMEX $US3.00/Mcf, AECO $2.40/GJ, FX rate US/CDN 1.30 2) Based on % of gross sales, before transportation 3) Excluding transportation costs 31

Advisories Assumptions All amounts are stated in Canadian dollars unless otherwise specified. Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent This presentation contains references to "BOE" (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. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at 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. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively. Non-GAAP Measures In this presentation, we use the terms adjusted funds flow", net debt to adjusted funds flow ratio, netback, net operating income, and "free cash flow" as measures to analyze leverage, liquidity and operating performance. These measures do not have any standardized meaning under United States GAAP ( U.S. GAAP ) and are therefore, considered Non-GAAP measures. Adjusted funds flow is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. Net debt to adjusted funds flow ratio is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash and restricted cash, divided by a trailing 12 months of funds flow. Netback and net operating income are calculated as oil and gas revenues after deducting royalties, operating costs and transportation expenses. Free cash flow is calculated as netback ( net operating income ), less capital spending (refer to Non-GAAP Measures in the Second Quarter 2017 and 2016 Annual MD&A for netback, which is used to calculate free cash flow). Enerplus believes that, in addition to cash flow, net earnings and other measures prescribed by U.S. GAAP, the terms adjusted funds flow", net debt to adjusted funds flow ratio, netback, net operating income, and "free cash flow are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by U.S. GAAP and do not have standardized meaning prescribed by U.S. GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see additional disclosure and reconciliations to certain of these Non-GAAP Measures in the MD&A. Presentation of Production and Reserves Information Under U.S. GAAP, oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under IFRS and Canadian industry protocol, oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. To remain comparable with our Canadian peer companies, the summary results contained within this presentation presents our production and BOE measures on a before royalty company interest basis. In addition, initial test results and production performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate recovery. Readers are cautioned that the average initial production rates contained in this presentation are not necessarily indicative of long-term performance or of ultimate recovery. All production volumes and revenues presented herein are reported on a company interest basis, before deduction of Crown and other royalties, plus Enerplus royalty interest. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on gross reserves" using forecast prices and costs. Gross reserves" (as defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101")), being Enerplus working interest before deduction of any royalties. Our oil and gas reserves statement for the year ended December 31, 2016 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, and is contained within our Annual Information Form for the year ended December 31, 2016 ("our AIF") which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are 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 for more complete disclosure on our operations. Discovered Petroleum Initially-In-Place, Discovered Original Oil-In-Place and Discovered Original Gas In Place Discovered Petroleum Initially-In-Place ( PIIP ) is that quantity of petroleum that is estimated to be contained in known accumulations prior to production. The recoverable portion of discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable. Discovered Original Oil in Place ( OOIP ) is not defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP for our North Dakota assets were provided by an independent estimate by McDaniel & Associates Ltd. dated June 9, 2014 and as of June 1, 2014. Discovered OOIP pertaining to our Canadian waterflood assets are estimates by internal qualified reserves evaluators, combined for all Canadian waterflood assets. Discovered Original Gas In Place ( OGIP ) is not defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Discovered OGIP as used in the presentation is the natural gas portion of PIIP. Discovered OGIP for our Marcellus shale gas assets are estimates prepared internally by Enerplus. See our AIF for disclosure of specific categories assigned to our reserves and contingent resources, a copy of which is available under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is available at www.sec.gov. 32

Advisories Contingent Resources Estimates This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with oil and gas reserves. The estimates of contingent resources included in this presentation pertaining to Canadian waterflood assets and Fort Berthold were evaluated by Enerplus internal qualified reserves evaluators and audited by independent reserves evaluators, McDaniel & Associates Ltd. The estimates of contingent resources included in this presentation pertaining to the U.S. Shale Gas-Marcellus were evaluated by independent reserves evaluators, Netherland, Sewell & Associates, Inc. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economics, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. All of our contingent resources estimates are economic using established technologies and based on January 1, 2017 forecast prices of McDaniel & Associates Ltd. Enerplus expects to develop these contingent resources in the coming years, however it is too early in their development for these resources to be classified as reserves at this time. There is no certainty that it will be commercially viable for us to produce any portion of the volumes currently classified as contingent resources. Development pending contingent resources refer to a contingent resources project maturity sub-class for a project where resolution of the final conditions are being actively pursued (there is a high chance of development) and the project is expected to be developed in a reasonable timeframe. The contingent resources estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered. Contingent resources estimates are effective as of December 31, 2016. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. For additional information regarding the primary contingencies which currently prevent the classification of our disclosed contingent resources associated with our Marcellus shale gas properties, our Fort Berthold properties, and a portion of our Canadian waterflood properties as reserves, and the positive and negative factors relevant to the "contingent resource estimates, see Appendix A to our AIF, a copy of which is available under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is available at www.sec.gov. Drilling Inventory Drilling locations associated with proved plus probable undeveloped reserves have been evaluated or reviewed by Enerplus independent qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook ). Drilling locations associated with unrisked best estimate economic contingent resources in development pending project maturity sub-class pertaining to Canadian waterflood assets and Fort Berthold have been evaluated by internal qualified reserves evaluators and audited by Enerplus independent qualified reserves evaluators, McDaniel & Associates Ltd, in accordance with the COGE Handbook. Drilling locations associated with unrisked best estimate economic contingent resources in development pending project maturity sub-class pertaining to the U.S. Shale Gas-Marcellus been evaluated by Enerplus independent qualified reserves evaluators, Netherland, Sewell & Associates, Inc, in accordance with the COGE Handbook. Unbooked future drilling locations are not associated with any reserves or contingent resources of Enerplus, and have been identified by internal qualified reserves evaluators and have not been audited by Enerplus independent qualified reserves evaluators. Finding & Development ( F&D ) Costs F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved developed producing ( PDP ) reserves, by dividing the sum of the exploration and development costs incurred in the year, by the additions to PDP reserves in the year; (ii) the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated proved future development costs in the year, by the additions to proved reserves in the year, and (iii) in the case of F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated proved plus probable future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs related to its reserves additions for that year. NOTICE TO U.S. READERS The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above with respect to production information, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period. Additionally, the SEC prohibits disclosure of oil and gas resources in SEC filings, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see Contingent Resources Estimates above. 33