Corporate Presentation December 2018

Transcription

1 Corporate Presentation December 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$66.86/bbl, a forward NYMEX gas price of US$2.96/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$3.1 billion C$0.4 billion C$3.5 billion Canadian Oil Waterfloods Production (2) : 9,670 BOE/d Key Messages Robust light oil growth out of North Dakota Differentiated margin expansion Fully funded plan Williston Basin Production (2) : 46,709 BOE/d Marcellus (NE PA) Production (2) : 210 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 September 30, ) Third quarter 2018 average production 2

4 Q Highlights STRONG RETURNS ON CAPITAL AND PROFITABLE GROWTH Outlook on track Capital & cost discipline Financial strength Return of capital Encouraging DJ Basin wells Production guidance increased to upper end of range Expecting 22% YOY liquids growth Capital budget unchanged at $585 million Reduced cash G&A guidance to $1.50/BOE Net debt to adjusted funds flow: 0.4x Visibility to meaningful free cash flow in Q Repurchased $25 million in shares in Sep/Oct Expect to allocate portion of free cash flow to further repurchases (1) 4 new wells tracking 100,000 barrels of oil per well in first year Successful Niobrara well (4 Codell, 1 Niobrara well drilled to date) 1) Based on prevailing market conditions at the time of Q3 earnings release 3

5 2018 Update Light Oil Growth, Capital Discipline and Free Cash Flow Liquids production tracking high end of the guidance range projecting 22% YOY growth No significant change to capital plan outlook remains within original budget Positioned for meaningful free cash flow in Q4 Oil Growth Tracking Top of Range 2018 Liquids Production Growth Rate +22% (vs. 2017) Maintaining Capital Discipline 2018 E&D Capital Budget (C$MM) Robust Cash Flow Generation 2018 Cumulative Adjusted Funds Flow (C$MM) $800 Strong Free Cash Flow Outlook in Q4 +18% (vs. 2017) $535-$585MM $585MM $600 $539 $400 $329 $200 $155 Original Guidance (1) Current Outlook Original Budget Current Outlook $0 Q1 Q2 Q3 Q4E 1) Based on midpoint of original guidance 4

6 Strong Returns, Free Cash Flow and Competitive Oil Growth Comparison to North American Peers (1) Return on Capital Employed (2) 2018E Free Cash Flow Yield (2) 2018E Liquids Production Growth (2) 2018E / ERF % 4 5% 4 22% Peer median = 7% Peer 19 median = -7% 19 Peer median = 22% 20-5% 5% 15% 25% % -10% 10% 30% % 20% 40% 60% 80% 1) 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 2) Based on Factset consensus Nov 28, Return on Capital Employed = EBIT/(avg. shareholder equity + avg. net debt). Free Cash Flow = operating cash flow - capex 5

7 Executing Profitable Growth Driving High-Return Bakken 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 of ~20% Light Oil Production Growth Liquids Production (Mbbl/d) ~20% CAGR (1) Strong cash flow generation Higher benchmark prices and improved realizations Increasing oil production mix Lower cost structure 0 $800 $700 $600 $500 $400 $300 $200 $100 $ E 2019E Driving Cash Flow Higher Adjusted Funds Flow (C$ millions) (2) 1) 2016 & 2017 excludes production from assets divested in 2016 & ) 2018 adjusted funds flow based on analyst consensus estimates at November 28, 2018 (1) (1) ~140% GROWTH E 6

8 Cash Margin Expansion Strong Cost Control and Tighter Differentials Driving Margin Expansion Lowering Cost Structure While Increasing Oil Production Weighting Improved Realized Pricing from Tighter Bakken & Marcellus differentials C$/BOE $15.79 $2.22 $1.65 $2.69 $13.14 $1.50 $1.04 $ % REDUCTION Corporate Oil Price Differential vs. WTI (US$/bbl) ($5.82) ($6.17) ($9.38) ($10.79) $9.23 $7.00 ($14.71) 58% IMPROVEMENT E Opex Transportation Interest G&A Q1-Q % 3% INCREASE TO 55% LIQUIDS WEIGHTING 5% Corporate Natural Gas Price Differential vs. NYMEX (US$/Mcf) ($0.45) 46% IMPROVEMENT ($0.66) 39% 50% ($0.84) ($0.98) ($0.91) Q3 NGL as % of Company Production Oil as % of Company Production Q1-Q

9 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 Cdn Peer Median Peer 14 Peer 15 Peer 16 Peer 17 Peer 18 Peer 19 Peer 20 Peer 21 US Peer Median 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 Strong Financial Flexibility Net Debt / 2018E Cash Flow (1) 14.0x 12.0x 10.0x 8.0x 6.0x 4.0x 2.0x 2.0x 2.6x 0.0x 0.4x 1) Source: Factset consensus Nov 28, 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 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 Balance Sheet & Liquidity Position (Sept 30, 2018) C$ Cash ($MM) $348 Senior Notes ($MM) $ % interest rate (1) Debt, net of cash ($MM) $313 Only debt outstanding are senior notes with no significant maturities until 2020 C$800MM credit facility is undrawn Bank credit facility ($MM) $800 Undrawn Senior Notes Repayment Schedule (C$ millions) $130 $105 $105 $104 $104 $58 $27 $27 Track record of prudent leverage management Net Debt / Trailing 12-Month Adjusted Funds Flow (2) 3x 2x 1x 0x 2.5x 1.4x 1.3x 1.2x 0.6x 0.4x Sep-18 1) Senior notes outstanding at September 30, 2018 comprise CDN$30MM and US$489MM. U.S. dollar denominated notes translated at September 28, 2018 FX rate of USD/CDN Senior notes are rated NAIC 2 (investment grade) by the National Association of Insurance Commissioners; rank equally with the bank credit facility; weighted avg int 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 Hedging Summary Protecting Capital Program Economics Hedging program designed to protect economics of capital program (~90% oil weighted) Utilizing 3-way collar structures to protect downside with upside participation Crude Oil Hedging Summary (1) bbls/day; WTI US$/bbl Natural Gas Hedging Summary (1) Mcf/day; NYMEX US$/Mcf 40,000 35,000 Q4 2018E Net Oil Production (2) 200, ,000 Q4 2018E Net Natural Gas Production (2) 30,000 25, , , ,000 $3.43 x $ ,000 15,000 10,000 5,000 0 $61.10 x $52.48 x $42.74 $65.50 x $54.62 x $44.50 $53.73 $53.73 $72.50 x $57.50 x $46.88 Q WTI Swaps WTI 3 Way Collars 100,000 80,000 60,000 40,000 20,000 0 $3.43 x $2.75 Q NYMEX Collars 1) As of October 30, way collars are comprised of a sold put, a purchased put and a sold call. The total average deferred premium spent on 3 ways collars is US$1.60/bbl from Oct 1, 2018 to December 31, ) Q production based on midpoint of guidance and is net of royalty and production taxes. 10

12 Williston Basin North Dakota & Montana - Light Oil Assets Fort Berthold, ND Tier 1 acreage position WILLISTON BASIN NORTH DAKOTA & MONTANA High return light oil production growth Attracts ~75% of company s capital Q3 production 43,390 BOE/d (84% oil) Fort Berthold Sleeping Giant, MT Minimal capital expenditures Sleeping Giant (Elm Coulee) Low decline, strong free cash flow generator Q production: 3,319 BOE/d Enerplus leases 11

13 Fort Berthold, North Dakota Bakken / Three Forks Tier 1 Acreage Position Acreage position concentrated in core of play BAKKEN POSITION FORT BERTHOLD, NORTH DAKOTA 65,600 net acres Top quartile well performance in the basin Singularly unique asset in Bakken core ~3 wells drilled per unit on average, going to ~10 well ultimate density ~500 gross remaining undrilled locations (1)(2) Significant light oil production growth Q production up ~60% YOY Currently operating 2 drilling rigs Development Plan per DSU (~10 wells/unit) MIDDLE BAKKEN THREE FORKS 1 Enerplus leases Indian Reservation THREE FORKS 2 THREE FORKS 3 Certain deeper bench locations included in inventory in acreage where these zones are productive 1 Mile Well location Well lease line location 1) 2P reserves of 171 MMBOE and unrisked best estimate economic contingent resources of 79 MMBOE as at December 31, ) 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 12

14 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 13

15 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 Enerplus Average Proppant Intensity vs ND Peers (2) Proppant volume (lbs/lateral ft.) 250, , completions (105 wells) 2013 completions (20 wells) 2012 completions (23 wells) 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 14

16 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 Sept ,000 70,000 60,000 WELL ECONOMICS AT US$55/BBL WTI (3) Payout: <2 years IRR: ~50% Breakeven (10% IRR): US$40/bbl WTI 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 3) Well economics based on US$8mm total well cost, differential to WTI of US$3.80/bbl 2018, US$4.50/bbl in 2019, US$4.00/bbl 2020 and US$3.50/bbl thereafter and average 2P reserves booked/location (based on 2-mile lateral wells). Breakeven based on 10% rate of return. 15

17 Fort Berthold Significant Running Room Low existing well density Large remaining opportunity set is well defined Gross Locations (1)(2) 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 16

18 Industry Bakken Oil Production & Takeaway Capacity Basin has significant takeaway optionality with pipeline egress and rail capacity 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), Wood Mackenzie and ERF estimates 2) CBR = Crude-by-rail. CBR forecast assumes rail volumes remain static to 2018 levels 17

19 Differential to WTI (US$/bbl) Enerplus Bakken Realized Oil Price Differential Bakken differentials have significantly strengthened with improved egress out of basin Enerplus Realized Bakken Oil Price Differential US$/bbl $0 Q differentials expected to be temporarily wider Revising 2018 annual average Bakken differential guidance to US$3.80/bbl below WTI (from US$3.50/bbl) -$2 -$4 Fixed physical sales at ~US$3.00/bbl under WTI help mitigate recent differential weakness -$6 -$8 >US$9/bbl IMPROVEMENT BAKKEN PHYSICAL DIFFERENTIAL SALES (1) TERM VOLUME FIXED DIFFERENTIAL Q ,250 bbl/d -US$2.53/bbl ,000 bbl/d -US$3.00/bbl -$10 -$12 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 Q3 18 1) Fixed differentials are referenced to WTI 18

20 Marcellus Core Acreage Position in NE Pennsylvania Non-operated position in Marcellus dry gas core 36,000 net acres Q production: 210 MMcf/d MARCELLUS POSITION NE PENNSYLVANIA Low cost, highly productive inventory >10 year drilling inventory (1)(2) Consistent free cash flow generation Regional infrastructure buildout continuing to improve natural gas price differential Expecting 47% YOY differential improvement in 2018 Differential Improvement Increasing Free Cash Flow Free Cash Flow (C$MM) Modest Growth Asset Marcellus Production (MMcf/d) $60 $ $20 $ E 2017 Q1 18 Q2 18 Q3 18 1) 2P reserves of 918 Bcf and unrisked best estimate economic contingent resources of 738 Bcf at December 31, ) net future 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 19

21 Marcellus Cash Margin Expansion Driven by Improved Regional Pricing 2018 Marcellus cash margin expected to improve by ~US$1/Mcf since 2015 Differential Improvement Increasing Free Cash Flow Marcellus Cash Margin (US$/Mcf) Expansion of basin pipeline takeaway to continue to support pricing in Low cost structure, improved realized pricing and strong capital efficiencies expected to drive continued free cash flow 2018 Marcellus cash flow expected to exceed capital expenditures by >C$50MM $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $3.11 $3.00 $2.66 $2.46 $0.76 $0.40 $1.37 $0.93 $1.33 $1.29 $1.02 $1.00 $1.06 $1.27 $0.29 $ E Cash Margin Basis Differential Opex, Gathering, Trans, Royalty NYMEX Benchmark Price 20

22 Marcellus Well Results Performance Continuing to Track at or Above Expectations Capital Efficient and Highly Productive Drilling Inventory Average Cumulative Production per Well (Bcf) (1) 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' WELL ECONOMICS (2) EUR (Bcf) IRR Pretax 39% 18% Payout (Years) Breakeven (NYMEX) $2.29 $ Bcf 10 Bcf Months on Production 1) Based on >200 wells on production since January ) Well economics based on a NYMEX price of US$3.00/mcf, 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 21

23 Marcellus Takeaway Expansion and Price Differential Additional Pipeline Projects to Further Support Improved Pricing Marcellus / Utica Incremental Takeaway Projects MMcf/d 18,000 15,000 12,000 9,000 >7 BCF/d ADDED SINCE START 2018 >10 BCF/d INCREMENTAL PLANNED WB Xpress Mountaineer Express Atlantic Coast Mountain Valley Penn East Southwest Northeast 6,000 Atlantic Sunrise Nexus 3,000 Rover Phase 2 Rover Phase 1 Leach Xpress - Q1 18 Q3 18 Q1 19 Q3 19 Q1 20 Q3 20 Q1 21 Q3 21 Q1 22 Q3 22 Enerplus Marcellus Portfolio Differential and Transport Cost US$/Mcf Enerplus Marcellus Pricing Exposure % of Expected Marcellus Sales 2017A 2018E 2019E Avg. portfolio differential (1) ($0.76) ($0.40) ($0.30) Firm transport cost ($0.18) ($0.18) ($0.18) 60% IMPROVEMENT EXPECTED 52% 52% 4% 4% 16% 16% Leidy Other Gulf Coast TZ6 Non-NY Differential + transport ($0.94) ($0.58) ($0.48) 28% 28% 1) Average portfolio differential to NYMEX

24 Canadian Oil Waterflood Portfolio Large Oil in Place, Low Decline Production Assets under water or polymer flooding Significant resource: 0.8 bn bbls OOIP (1)(2) Low decline oil production Portfolio optimized to focus on highest return, strong cash flow generating assets Improved cost structures have driven margins higher ANTE CREEK ( ) CANADIAN WATERFLOODS Highly economic opportunity set with modest capital to maintain production levels Consistent Free Cash Flow Generation Free Cash Flow from Retained Assets (3) (C$MM) $500 $400 $300 $200 $100 >$400 MILLION IN FREE CASH FLOW SINCE 2012 $ YTD Stable, Low Decline Oil Production Production from Retained Assets (3) (MBOE/d) OIL GAS/NGL ) OOIP is discovered original oil in place and is estimated by internal qualified reserves evaluators. 2) 2P reserves of waterflood portfolio are 44.8 MMBOE and unrisked best estimate economic contingent resources are 34 MMBOE at December 31, Gross working interest 3) Production and free cash flow is from retained assets (excludes assets divested) YTD

25 Investment Thesis Track record of disciplined capital allocation and strong returns Robust light oil growth out of North Dakota Differentiated margin expansion Fully funded plan Balance sheet among the strongest in peer group Profitable, Sustainable, Resilient GROWTH 24

26 Supplemental Information

27 Guidance and Capital Allocation 2018 GUIDANCE (1) Capital Spending C$585 million Q4 Crude Oil & NGL Production 53,500-54,500 bbls/d Annual Average Production 92,500-93,000 BOE/d Annual Average Liquids Production 49,500-50,000 bbls/d Average Royalty & Production Tax Rate (2) 25% Operating Expense C$7.00/BOE 2018 E&D CAPITAL ALLOCATION (4) 75% NORTH DAKOTA 5% OTHER ASSETS 10% MARCELLUS 10% CANADIAN WATERFLOODS Transportation Expense Cash G&A Expense C$3.60/BOE C$1.50/BOE 2018 Bakken WTI Differential (3) US($3.80)/bbl 2018 Marcellus NYMEX Differential (3) US($0.40)/Mcf 1) 2018 guidance assumptions: WTI US$67.60/bbl, NYMEX US$2.95/Mcf, FX rate US/CDN ) Based on % of gross sales, before transportation 3) Excluding transportation costs 4) Capital allocation is approximate. Includes non-drilling and completion spending and capitalized G&A 26

28 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. 27

29 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 adjusted funds flow less exploration and development capital spending (refer to Non-GAAP Measures in the 2017 Annual and current year interim MD&A). 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 4: 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, 2017 ("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. 28

30 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. 29