Corporate Presentation September 2018

Transcription

1 Corporate Presentation September 2018

2 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 an asset-level basis, as applicable: expected average production volumes in 2018 and the anticipated production mix; a portion of production that is curtailed; 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 2018 along with its components and impact on our production levels and land holdings; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, and our tax pools and the time at which we may pay Canadian cash taxes; net operating income and future adjusted funds flow levels, including on 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 to retain value, or due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates, incentive programs or other regulatory matters; changes in 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, 2017). 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 2018 guidance herein is based on the following: a forward WTI price of US$66.00/bbl, a forward NYMEX gas price of US$2.84/Mcf, and US/CDN exchange rate of 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

3 Enerplus Overview TSX, NYSE ERF Market Cap Net Debt (1) Enterprise Value C$4.1 billion C$0.4 billion C$4.5 billion Canadian Oil Waterfloods Production (2) : 9,770 BOE/d Key Messages Robust light oil growth out of North Dakota Differentiated margin expansion Fully funded plan; free cash flow under strip prices Williston Basin Production (2) : 43,741 BOE/d Marcellus (NE PA) Production (2) : 202 MMcf/d Balance sheet among the strongest in peer group Focused on profitable, sustainable and resilient growth 1) Net debt is the principal amount of long-term debt and includes working capital. As at June 30, ) Second quarter 2018 average production 2

4 Q Highlights Production of 92,883 BOE/d Growth On Track Liquids production up 21% Q-o-Q to 50,050 bbls/d 33% production growth in North Dakota Q-o-Q On track for ~20% company liquids production growth in 2018 Adjusted funds flow of C$174MM, up 12% from Q1 Financial Strength Free cash flow: 2018 adj. funds flow to exceed capital & dividends by >C$100MM (1) Strong liquidity and financial flexibility: 0.5x net debt / adjusted funds flow ratio, C$800MM undrawn revolver Updated Guidance Targets (2) Annual average production increased to 91,000 to 93,000 BOE/d Liquids guidance revised to 49,000 to 50,000 bbls/d, the high-end of previous guidance Capex guidance tightened to C$585MM, largely due to increased non-op activity Cash G&A reduced C$0.10/BOE to C$1.55/BOE 1) Based on current strip pricing 2) See page 30 for details on guidance changes. 3

5 Strong Returns, Free Cash Flow and Competitive Oil Growth Return on Capital Employed 2018E Free Cash Flow Yield 2018E Liquids Production Growth 2018E / ERF % -5% 5% 15% 25% 1 ERF % -30% -20% -10% 0% 10% 1 ERF Peer median = 8% Peer median = -4% Peer median = 21% 21% 0% 20% 40% 60% 80% 1) Based on Factset consensus. Return on Capital Employed = EBIT/(avg. shareholder equity + avg. net debt). Free Cash Flow = operating cash flow - capex 2) Peers include: ARX, BIR, BTE, CPE, CPG, CRZO, DNR, EGN, EPE, KEL, LPI, MEG, MTDR, NVA, OAS, PDCE, PE, QEP, SM, SRCI, TOG, TOU, VII, WLL, WPX, WRD. Peers that closed significant production acquisitions have been excluded. 4

6 Executing Profitable Growth Driving High-Return Crude Oil Production Growth Plan grounded in returns based capital allocation Underpinned by high-return drilling inventory in North Dakota 3-year total company production CAGR of ~10% Liquids Production Growth Mbbl/day ~20% CAGR (1) Resilient growth Risk mitigation through hedging Conservative balance sheet provides significant financial flexibility Margin expansion to continue Driven by increasing crude oil production mix and improving price realizations E 2019E Cash Margin Expansion (2) C$/BOE $24 $20 $16 $12 $8 $4 (1) (1) Continued Improvement even in flat commodity price scenario Meaningful cash flow growth at US$60/bbl US$60/bbl US$50/bbl $ E 1) 2016 & 2017 excludes production from assets divested in 2016 & ) Cash margin is equal to revenue less royalties, production taxes, operating costs, transportation costs, G&A costs and interest costs & 2017 cash margins are based on realized results, E are based on flat pricing of US$50/bbl WTI, with upside shown at US$60/bbl WTI, and US$3/Mcf flat NYMEX natural gas 5

7 2018 Capital Allocation Disciplined Focus on Value and Returns Capital program and dividends funded within cash flow At US$50-55/bbl WTI and US$3.00/Mcf NYMEX >C$100MM in excess cash flow expected under current strip prices Focused on high-return North Dakota drilling Projecting >30% YoY production growth from North Dakota 2018E Capital Allocation (1) C$585 Million 75% NORTH DAKOTA 5% OTHER ASSETS 10% MARCELLUS 10% CANADIAN WATERFLOODS Liquids to account for more than 55% of total production by the 2018 Average Production Guidance second half of 2018 Total production (boe/d) 91,000 93,000 Liquids production (bbls/d) 49,000 50,000 1) Approximate capital allocation based on midpoint of guidance. Includes non-drilling and completion spending and capitalized G&A 6

8 Cash Margin Expansion 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 18% REDUCTION $15.79 $2.22 $2.09 $1.65 $1.71 $2.69 $15.50 $2.95 $9.23 $8.75 $13.53 $1.75 $1.33 $3.14 $7.31 $12.98 $1.63 $1.19 $3.60 $6.39 Improved Realized Pricing Corporate Oil Price Differential vs. WTI (US$/bbl) ($5.82) 60% IMPROVEMENT ($9.38) ($10.79) ($14.71) Corporate Natural Gas Price Differential vs. NYMEX (US$/Mcf) ($0.66) 21% IMPROVEMENT ($0.84) ($0.91) Opex Transportation Interest G&A ($0.98)

9 WTI Oil Price (US$/bbl) Cash Margin Expansion Significant Improvement Driven by Structural Changes Structural improvements to Enerplus cost structure and pricing realizations have helped increase its unhedged cash margin (1) by >$16/BOE Liquids production weighting expected to be >55% in H driven by Bakken oil growth $25 $80 >$16/BOE CASH MARGIN IMPROVEMENT $22.94 $70 Enerplus Cash Margin (C$/BOE) (1) $20 $15 $10 $5 $6.39 $8.22 $11.39 $14.88 $14.68 $12.10 $18.80 $19.01 $60 $50 $40 $30 $20 $10 $0 47% 46% 47% 43% 48% 49% 53% 49% 54% Q Q Q Q Q Q Q Q Q $0 WTI Oil Price Cash Margin % Liquids production weighting 1) Cash margin is equal to oil & gas sales less royalties, production taxes, operating costs, transportation costs, G&A costs and interest costs. Cash margin is unhedged 8

10 Balance Sheet & Liquidity Position Significant Financial Strength Enerplus strong balance sheet provides meaningful financial flexibility and supports the resiliency of its growth plans Only debt outstanding are senior notes with no significant maturities until 2020 C$800MM credit facility is undrawn Track record of prudent leverage management Balance Sheet & Liquidity Position (Jun 30, 2018) C$ Cash ($MM) $360 Senior Notes ($MM) $ % interest rate (1) Debt, net of cash ($MM) $312 Bank credit facility ($MM) $800 Undrawn Senior Notes Repayment Schedule (C$ millions) $132 $107 $107 $106 $106 $59 $28 $28 $ Net Debt / Trailing 12-Month Adjusted Funds Flow (2) 3.0x 2.5x 2.0x 1.0x 1.4x 1.3x 1.2x 0.6x 0.5x 0.0x H ) Senior notes outstanding at June 30, 2018 comprise CDN$30MM and US$489MM. U.S. dollar denominated notes translated at June 29, 2018 FX rate of USD/CDN 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% 2) Net debt to adjusted funds flow ratio is a non-gaap measure. Please refer to the Non-GAAP measures in the Q MD&A and Advisories for further detail 9

11 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 Cdn Peer Avg Peer 21 US Peer Avg Peer 22 Peer 23 Peer 24 Peer 25 Peer 26 Peer 27 Peer 28 Peer 29 Peer 30 Peer 31 Balance Sheet Strength Financial Position Among the Strongest In Peer Group Enerplus is committed to maintaining a strong balance sheet Net Debt / 2018E Cash Flow Source: BMO comps at strip pricing July 27, 2018 (1) 8.0x 7.0x 6.0x 5.0x 4.0x 3.0x 2.0x 2.0x 2.3x 1.0x 0.5x 0.0x 1) Peers: ARX, BIR, BTE, CPE, CPG, CRZO, DNR, ECR, EGN, EPE, KEL, LPI, MEG, MTDR, NVA, OAS, PDCE, PE, PEY, POU, SM, SRCI, SWN, TOG, TOU, VET, VII, WCP, WLL, WPX, WRD 10

12 Hedging Summary Protecting Cash Flow Crude Oil Hedging Summary (1)(2) bbls/day; WTI US$/bbl Natural Gas Hedging Summary (1)(2) Mcf/day; NYMEX US$/Mcf % HEDGED (3) 63% 69% 60% 70% 73% 73% 42% % HEDGED (3) 21% 16% 25,000 80,000 20,000 60,000 15,000 10,000 $61.22 x $52.53 x $42.71 $61.10 x $52.48 x $42.74 $64.12 x $54.12 x $ ,000 5,000 - $53.73 $53.73 $53.73 $65.52 x $54.59 x $44.50 $65.95 x $54.81 x $44.64 $65.99 x $54.81 x $44.64 $72.07 x $57.14 x $46.71 Q Q Q Q Q Q Cal ,000 0 $3.38 x $2.75 Jul18-Oct18 $3.47 x $2.75 Nov18-Dec18 WTI Swaps WTI 3 Way Collars NYMEX Collars 1) As of August 9, ) 3-way collars are comprised of a sold put, a purchased put and a sold call. The total average deferred premium spent on our 3 ways collars is US$1.59/bbl from July 1, 2018 to December 31, ) 2018, 2019 and 2020 percentages are based on 2018 forecast annual average crude and natural gas volumes respectively, net of royalties 11

13 Reserves Strong Organic Replacement at Competitive Costs Replaced 189% of 2017 production 2P Organic Reserves Replacement (1) 189% 2P Finding & Development Costs (C$/boe) (2) 414% in North Dakota 132% in Marcellus 108% 126% $8.44 $9.68 $4.82 Competitive F&D costs with over 80% of capital directed to oil plays over last three years P Reserves by Area (3) 2P Reserves by Commodity (3) 2P Reserves by Category (3) 1P reserves account for 70% of 2P; PD reserves account for 47% of 2P 3% 11% 47% 5% 48% 30% 47% 47% 39% 23% Williston Basin Other Marcellus Cdn Waterfloods Oil Gas NGL PD PUD Probable 1) 2P is proved plus probable reserves. Replacement defined as sum of extensions, discoveries, revisions and economic factors, divided by annual production 2) Finding and development costs include future development capital 3) At December 31, PD is proved developed reserves, PUD is proved undeveloped reserves. 12

14 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 2018 Q production: 40,479 BOE/d Sleeping Giant (Elm Coulee) Fort Berthold Sleeping Giant, MT Q production: 3,262 BOE/d Minimal capital expenditures; low decline strong free cash flow generator Enerplus leases 13

15 Fort Berthold, North Dakota Bakken / Three Forks Tier 1 Acreage Position Key Details Net Acreage (operated) 65,600 acres Average WI (%) 84% Q Production (BOE/day) 40,479 % Crude Oil, NGL & Gas (at Q2) 82%, 9%, 9% 2P Reserves (MMBOE) (1) 171 Contingent Resources (MMBOE) (2) 79 Future Drilling Locations (3) 506 Gross (422 Net) Operated drilling rigs 2 Development Plan per DSU (~10 wells/unit) Middle Bakken Enerplus leases Indian Reservation 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) Gross working interest at December 31, ) Unrisked best estimate economic contingent resources as at December 31, See the 2017 Annual Information Form Appendix A for more detail 3) Future drilling locations as at December 31, Net locations includes 114 proved plus probable undeveloped reserves locations, 158 best estimate contingent resources locations, and 151 unbooked future locations. Unbooked future locations are internal estimates and have not been audited by external evaluators. See Advisories 14

16 Depth (000 ft) Fort Berthold Efficiencies Focused on Continuous Improvement Continued improvement in drilling efficiencies and more pad development is driving ~30% increase in wells drilled year-over-year Meaningful production growth forecast in 2018 with unchanged rig count Drilling Efficiency Gains Spud to Rig Release, 2-Mile Lateral Drilling Efficiency Gains Wells drilled per year Production Growth Operated North Dakota (MBOE/d) (1) 0 Days >100% INCREASE WELLS/RIG/YEAR SINCE >30% GROWTH YOY IN Avg. 2018E E Operated drilling rigs Gross operated wells drilled E 1) Excludes non-operated production 15

17 Enerplus Completion Evolution Focus on Continuous Improvement Driving Modifications to Completions Design Aiming to maximize economics through: Achieving similar well performance at lower proppant intensity (and lower cost) Improving well performance at higher proppant intensity (and higher cost) Enerplus Operated Well Performance (1) Cumulative barrels of oil 250, , completions (91 wells) 2013 completions (20 wells) 2012 completions (23 wells) Enerplus Average Proppant Intensity vs ND Peers (2) Proppant volume (lbs/lateral ft.) 2,000 1,800 1,600 Upper Quartile (Peer wells) Lower Quartile (Peer wells) Median (Peer wells) Enerplus Average 150,000 Increasing proppant intensity 1,400 1,200 1, , , Producing Days ) Includes all Enerplus operated 2-mile lateral wells 2) Source: IHS 16

18 Top Quartile Well Productivity Core Acreage and Completion Design Delivering Top Quartile Performance Cumulative Oil Production per 1,000 Lateral Feet (1)(2) Barrels of oil, North Dakota wells since 2014 through May ,000 70,000 60,000 50,000 40,000 30,000 20,000 10, ,000 1,200 1,400 1,600 Days Industry Bakken/Three Forks wells ERF Three Forks wells ERF Bakken wells 1) Source: IHS 2) Chart excludes the EOG operated Riverview H well with cumulative production/1000 ft. of 113,900 through 1,096 days on production 17

19 Fort Berthold Significant Running Room Low existing well density Large remaining opportunity set is well defined Gross Locations (1) Wells Drilled & Future Drilling Locations ~10 wells/ DSU ~2.7 wells/ DSU ~4 wells/ DSU ~7 wells/ DSU >500 UNDRILLED LOCATIONS 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, Gross locations includes 130 proved plus probable undeveloped reserves locations, 185 best estimate development pending contingent resources locations, and 191 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

20 Industry Bakken Oil Production & Takeaway Capacity Pipeline takeaway and refining capacity estimated to exceed existing basin production (net of current crude by rail volumes) by ~300,000 bbls/day Bakken Crude Oil Production and Takeaway Capacity Mbbl/d 3,000 Total basin egress 2,500 2,000 Dakota Access Pipeline operational 1,500 Remaining pipe capacity 1, Historical crude-by-rail movements Crude-by-rail forecast assumption (2) Refining NDPA CBR Forecast CBR Pipe Rail Loading Available Production Total Egress 1) Source: North Dakota Pipeline Authority (NDPA) and Wood Mackenzie. 2) CBR = Crude-by-rail. CBR forecast assumes rail volumes remain static to 2018 levels 19

21 ERF Realized Differential to WTI (US$/bbl) Oil Price (US$/bbl) % of WTI Price Enerplus Bakken Realized Crude Oil Price Bakken differentials have significantly strengthened with improved egress out of basin Enerplus is guiding to a 2018 realized Bakken differential of US$(3.50)/bbl to WTI Enerplus Bakken Crude Oil Differential US$/bbl $0 Enerplus Bakken Crude Oil Price Realizations $80 100% -$2 $70 95% -$4 -$6 $60 $50 90% $40 85% -$8 -$10 >US$8/bbl IMPROVEMENT $30 $20 80% -$12 $10 75% -$14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 $0 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q % Realized Bakken Price Differential % of WTI 20

22 Marcellus Core Acreage Position in NE Pennsylvania Key Details Net Acreage 36,200 acres Average WI (%) 11% Q Production (MMcf/day) 202 % Natural Gas (at Q1) 100% 2P Reserves (Bcf) (1) 918 Contingent Resources (Bcf) (2) 738 Future Net Drilling Locations (3) Net 100% non-operated position Enerplus leases Acreage located in NE PA dry gas core Low cost, highly productive drilling inventory 1) Gross working interest at December 31, ) Unrisked best estimate economic contingent resources at December 31, See the 2017 Annual Information Form Appendix A for more detail 3) Future net drilling locations as at December 31, Includes 29.5 proved plus probable undeveloped reserves locations and 71.2 best estimate contingent resources locations. See Advisories 21

23 Marcellus Well Results Continued Strong Performance Well performance continuing to track at or above type curve expectations Average Cumulative Gas Production (1) Bcf 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' 15 Bcf 10 Bcf Well Economics (3) EUR (Bcf) NYMEX (US$/Mcf) $3.00 IRR Pretax 39% 18% Payout (Years) Breakeven (NYMEX) $2.29 $ Months on Production 1) Based on wells on production since January ) Well economics based on a total well cost of US$5.5 million and 5,500 ft. lateral. Basis differentials to NYMEX: US$0.40/Mcf and 2019 & beyond -US$0.30/Mcf. Transport cost of US$0.18/Mcf. Breakeven based on a 10% rate of return 22

24 Marcellus Basis Improvement to Drive an Increase in Free Cash Flow Low cost operations consistently delivering free cash flow, with further margin expansion expected in 2018 Marcellus Cash Margin Expansion US$/Mcf $3.50 $3.00 $2.50 $2.66 $2.46 $3.11 $0.76 $3.00 $0.40 Marcellus Capital Spending & Net Operating Income US$ millions $90 $80 $70 $60 FREE CASH FLOW GROWTH FROM BASIS IMPROVEMENT (1) $2.00 $50 $1.50 $1.37 $0.93 $40 $1.00 $0.50 CONTINUED MARGIN EXPANSION $30 $20 $10 $ E Basis Differential Opex, Transport, Gathering, Royalty Cash Margin NYMEX $ E 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 December 31, 2017 MD&A regarding non-gaap measure components used to calculate free cash flow. 2018E net operating income based on US$3.00/Mcf NYMEX and basis differential of US($0.40)/Mcf (plus transportation costs of US$0.18/Mcf) below NYMEX 23

25 Bcf/d Marcellus/Utica Pipeline Projects Meaningful Expansion Projects Will Debottleneck the Region Combined 6.2 Bcf/d of additional pipeline projects expected in-service across Northeast Pennsylvania and Southwest Marcellus/Utica during Q2 Q NE Pennsylvania Pipeline Projects Marcellus / Utica Incremental Takeaway Projects 15 >4 Bcf/d INCREMENTAL TAKEAWAY Q Bcf/d 2.1 Bcf/d 2.4 Bcf/d Q Estimated NE PA Production H H H H H H ) Source: Company estimates, Bentek Northeast Observer report SOUTHWEST MARCELLUS / UTICA Capacity Project (mmcf/d) In-Service Access South 320 Q Adair Southwest 200 Q Rover Phase 1B 300 Q Leach XPress 1,500 Q Rover Phase 1C 1,000 Q Broad Run Exp. 200 Q Rover Phase 2 1,300 Q NEXUS 1,500 Q WB XPress 1,300 Q Eastern Panhandle Exp. 48 Q Mountaineer Xpress 1,825 Q Equitrans Exp. Project 600 Q Mountain Valley 2,000 Q Atlantic Coast 1,500 Q Bcf/d INCREMENTAL NORTHEAST MARCELLUS Capacity Project (mmcf/d) In-Service Connecticut Exp. 72 Q DTI New Market 112 Q Leidy South Project 155 Q Orion 135 Q Susquehanna West Exp. 145 Q Triad Exp loop 180 Q Atlantic Sunrise 1,700 Q Eastern Market Access 294 Q Atlantic Bridge 133 Q Empire North Exp. 300 Q Penn East 1,000 Q Constitution 650 Q Northern Access 497 Q Bcf/d INCREMENTAL 24

26 Marcellus Marketing Portfolio Marcellus Marketing Portfolio MMcf/d ERF Q Marcellus Production Monthly/Daily sales at Leidy Firm Sales Existing Transportation Capacity Jan-18 Jul-18 Jan-19 Jul-19 PennEast (1) Expected Pricing Exposure Based on Q production volumes 100% 90% 80% 70% 60% TZ6 Non-NY Other Gulf Coast Leidy 52% 52% Estimated Marcellus Portfolio Differential and Transport Cost US$/Mcf 2017A 2018E 2019E Average portfolio differential ($0.76) ($0.40) ($0.30) Firm transport cost ($0.18) ($0.18) ($0.18) Differential + transport ($0.94) ($0.58) ($0.48) 50% 40% 30% 20% 10% 0% 4% 4% 16% 16% 28% 28%

27 Canadian Oil Waterflood Portfolio Large Oil in Place, Low Decline Production High netback, free cash flow generating assets Activity focused on waterflood optimization and expansion, and ongoing polymer flooding Discovered OOIP (1) (bbls) 0.8 billion Average WI (%) 87% Q Production (BOE/day) 9,770 ANTE CREEK ( ) % Crude Oil, NGL & Gas (at Q2) 92%, 1%, 7% 2P Reserves (2) (MMBOE) 44.8 Contingent Resources (3) (MMBOE) 34 Average Decline Rate (%) (4) 15 1) Estimated by internal qualified reserves evaluators. See Advisories 2) Gross working interest at December 31, ) Unrisked best estimate economic contingent resources at December 31, See the 2017 Annual Information Form Appendix A for more detail 4) Excludes Ante Creek 26

28 Canadian Oil Waterflood Portfolio High-Margin, Stable Production Portfolio optimized to focus on highest returning, strong cash flow generating assets Improved cost structures of retained assets helping to drive meaningful free cash flow from waterflood portfolio Modest capital requirements to maintain Free Cash Flow Generation - Waterflood Portfolio (1)(2) C$ Million, Cumulative Free Cash Flow from Retained Assets (Unhedged) $450 $400 $350 $300 $250 $200 $150 $100 $50 $0 Q Q production levels Stable, Low Decline Production Waterflood Portfolio (2) BOE/d from Retained Assets 14,000 12,000 10,000 8,000 6,000 4,000 2,000 - Q Q Q Q Q Q ~$400 MILLION IN FREE CASH FLOW SINCE 2012 Q Q Q Q Q ) Free cash flow is a non-gaap measure and is calculated as net operating income (netback before hedging) less capital expenditures 2) Production and free cash flow shown is from retained assets (excludes assets divested) 27

29 Why Invest in Enerplus Key Messages Robust light oil growth out of North Dakota Differentiated margin expansion Fully funded plan; free cash flow under strip prices Balance sheet among the strongest in peer group Profitable, Sustainable, Resilient GROWTH 28

30 Supplemental Information

31 2018 Guidance (1) 2018 Capital Spending Annual Average Production Annual Average Crude Oil & NGL Production C$585 million (from C$ million) 91,000 93,000 BOE/d (from 86,000-91,000 BOE/d) 49,000 50,000 bbls/d (from 46,000-50,000 bbls/d) Average Royalty & Production Tax Rate (2) 25% Operating Expense Transportation Expense Cash G&A Expense C$7.00/BOE C$3.60/BOE C$1.55/BOE (from C$1.65/BOE) 2018 Bakken WTI Differential (3) US($3.50)/bbl 2018 Marcellus NYMEX Differential (3) US($0.40)/Mcf 1) 2018 guidance assumptions: WTI US$60.00/bbl, NYMEX US$3.00/Mcf, FX rate US/CDN ) Based on % of gross sales, before transportation 3) Excluding transportation costs 30

32 Reducing Leverage and Abandonment Liabilities Net debt reduced ~75% since YE 2015 (1) Senior notes outstanding: $672 MM (2) and cash of $360 MM Divestment activity has reduced ARO by ~58% since YE 2014 Debt, net of cash (1)(2) C$ 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 $150 $122 $400 $200 $0 ~75% REDUCTION $312 YE 2015 Q $100 $50 $0 ~58% REDUCTION YE 2014 H ) Net debt at June 30, 2018 consists of total debt of $672 MM and cash of $360MM 2) Senior notes outstanding at June 30, 2018 comprise CDN$30MM and US$489MM. US dollar denominated notes translated at June 29, 2018 FX rate of USD/CDN

33 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 cash flow 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, 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 2017 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. Third party ROCE Calculation on slide 5: Macquarie calculates Return on Capital Employed (ROCE) = (adjusted net income + after-tax interest) / [(sum FY Est debt from time t-1 to time t divided by two) + (sum FY est shareholder s equity from time t-1 to time t divided by two) + (sum FY est minority interest from time t-1 to time t divided by two) (sum FY est cash from time t-1 to time t divided by two) + (sum FY est cumulative impairment from t-1 to time t divided by two)]. ROCE may vary significantly company to company due to differences in accounting methods, reserves booking and choice of depletion and depreciation methods. 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 Standards of Disclosure for Oil and Gas Activities ("NI ")), being Enerplus working interest before deduction of any royalties. Our oil and gas reserves statement for the year ended December 31, 2017 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI , and is contained within our Annual Information Form for the year ended December 31, 2016 ("our AIF") which is available on our website at and under our SEDAR profile at 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 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 and does not have a standardized meaning under NI Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP pertaining to our Canadian waterflood assets are estimates by internal qualified reserves evaluators, combined for all Canadian waterflood assets. 32

34 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, 2018 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, 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 the most recent AIF, a copy of which is available under our SEDAR profile at and our Form 40-F, a copy of which is available at 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