ERF: TSX & NYSE FirstEnergy Global Energy Conference September 21, 2015
Forward Looking Information Advisory 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: expected 2015 average production volumes and the anticipated production mix; average production volumes associated with operator-led curtailment in the Marcellus; the proportion of our anticipated oil and gas production that is hedged; 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 2015 and their impact on our production levels; potential future asset impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. taxes; future funds flow levels; future debt and working capital levels and debt-to-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 dispositions, including expected proceeds therefrom and production volumes associated therewith. 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: changes in commodity prices; changes in realized prices for Enerplus products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from development plans or production declines; changes in tax or environmental laws, royalty rates, incentive programs or other regulatory matters; changes in development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; inaccurate estimation of Enerplus' oil and gas reserves and 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 AIF and Form 40-F, described below and under Risk Factors and Risk Management in our MD&A, for the year ended December 31, 2014). 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 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; the availability of third party services; and the extent of our liabilities. In addition, our 2015 revised guidance contained in this presentation is based on the July 22, 2015 forward market WTI price of US$51.99/bbl, NYMEX gas price of US$2.89/Mcf, AECO gas price of $2.75/GJ and USD/CDN exchange rate of 1.27. 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 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
Strategy: Sustainable Growth & Income Top Tier Assets Operational Excellence Conservative Financial Strategy Top resource plays in North America Significant organic drilling inventory Proven technical expertise Disciplined, return focused capital allocation Focus on profitability Strong balance sheet Hedging strategy provides cash flow protection Sustainable Organic Growth & Income 2
Track Record: Organic Production Growth Production growth driven by North Dakota and the Marcellus Production Growth (1)(2) 2015E Production by Product & Location (1) BOE/day 105,000 100,000-104,000 90,000 75,000 0.18 0.18 44% Natural Gas 56% Crude Oil & NGL 0.16 60,000 0.15 0.15 45,000 30,000 10% 10% Williston Basin 30% Marcellus 15,000 0 2011 2012 2013 2014 2015E 20% 30% Canadian Waterfloods Canadian Deep Basin Other Natural Gas Crude Oil & NGL BOE/Share 1) 2015E is based on guidance of 100,000 104,000 BOE/day. Production per share is based on the mid point of guidance 2) CAGR (compound annual growth rate) based on BOE/day 2011-2014 3
Track Record: Consistent Reserves Growth 2P Reserves Growth (1) 2014 Reserves by Category & Location (1)(2) MMBOE 450 400 350 300 300 316 341 401 1.98 429 2.09 34% PDP+PDNP PUD 53% Probable 13% 250 1.70 1.74 1.72 200 150 100 50 0 2010 2011 2012 2013 2014 20% 14% 33% 34% Williston Basin Marcellus Canadian Oil Canadian Gas Natural Gas Crude Oil & NGL BOE/Share 1) Gross reserves as at December 31 2) Reserves by location are based on 2P reserves 3) CAGR (compound annual growth rate) based on MMBOE 2010-2014 4
Track Record: Improving F&D and On-Stream Costs 2014 recycle ratio of 2.7x Strong operational focus driving improvement in capital efficiencies 2P F&D and FD&A Costs (1) Capital Efficiencies (2) $/BOE $/BOE/day $25 $20 $24.21 $22.92 $70,000 $60,000 $60,000 $50,000 $15 $10 $11.28 F&D 3 year: $14.26 FD&A 3 year: $12.13 $9.80 $8.36 $8.62 $40,000 $30,000 $35,000 $26,000 $22,500 $20,000 $5 $10,000 $0 2012 2013 2014 F&D costs FD&A costs $0 2011 2012 2013 2014 1) Including future development capital 2) Capital efficiency is calculated as the change in production from the fourth quarter of the previous year to the fourth quarter of the current year, including base decline, divided by total capital expenditures from the fourth quarter of the previous year up to and including the third quarter of the current year. 2014 excludes the impact of Marcellus production curtailment 5
Sustainability and Conservative Balance Sheet Adjusted payout ratio, inclusive of A&D, is projected to remain below 100% in 2015 Q2 2015 total net debt $1.1 billion Sustainability (1)(2)(3) Balance Sheet Strength (4) $ Millions APO Net Debt $ Millions Debt/ Funds Flow 1,200 1,000 800 600 400 200 174% 160% 114% 118% 98% 97% 127% 93% 200% 180% 160% 140% 120% 100% 80% 1,200 1,000 800 600 400 200 $901 1.6 $574 $1,064 1.7 $645 $1,022 $754 1.4 $1,135 $1,121 $859 1.3 1.6 $695 2.5 2.0 1.5 1.0-2012 2013 2014 2015E 60% - 2011 2012 2013 2014 30-Jun-15 0.5 Capital + Dividends APO Funds Flow APO, inclusive of A&D Net Debt Funds Flow Debt/Funds Flow 1) APO (Adjusted Payout Ratio) is calculated as cash dividends plus capital and office expenditures divided by funds flow 2) 2015E funds flow based on analyst consensus September 1, 2015 3) 2015E includes proceeds of announced A&D to date 4) Debt/funds flow ratio is based on debt outstanding net of cash and the trailing twelve months of funds flow 6
2015 Capital Allocation Disciplined Spending Capital spending reduced by 30% from 2014 levels Majority of capital being directed to oil properties 2015 Capital Allocation ($540 million) Drilling Activity - First Half 2015 (1) U.S. Gas 5% Canadian Gas 5% Wells Drilled Wells On-stream U.S. Oil 13.7 12.8 Canadian Oil 15.4 17.5 Canadian Oil 25% U.S. Gas 2.9 6.1 Canadian Gas 3.7 3.0 Total Oil 29.1 30.3 Total Gas 6.6 9.1 Total 35.7 39.4 U.S. Oil 65% 1) Net drilling activity 7
bbl/d hedged WTI Price Hedged (US$/bbl) MMcf/d Hedged NYMEX Price Hedged (US$/Mcf) Hedging Summary Crude Oil Hedging Summary (1) Natural Gas Hedging Summary (1) % of forecast production 25% 45% 34% 34% 57% 38% 9% hedged (2) 16,000 $104 180 $4.5 14,000 $91 160 $4.0 12,000 $78 140 $3.5 10,000 $65 120 $3.0 8,000 $52 100 80 $2.5 $2.0 6,000 $39 60 $1.5 4,000 $26 40 $1.0 2,000 $13 20 $0.5 0 Q3 2015 Q4 2015 1H 2016 2H 2016 $0 0 Q3 2015 Q4 2015 FY 2016 $0.0 Hedged Volume Floor Price Hedged Volume Floor Price 1) In some cases the floor price is based on 3-way collar structures where the actual floor price may be affected by the underlying commodity price. See Supplementary Information in the back of this presentation for additional information on hedging program 2) % of forecast production hedged is based on volumes after royalties and production taxes, and based on annual average production of 100,000 104,000 BOE/day for 2015 and 2016 8
2015 Guidance: Well Positioned 2015 Guidance and Performance to Date 2015 Guidance Revised First Half 2015 Guidance (1) Actuals Capital Spending $540 MM $540 MM $315 MM AA Production (BOE/d) 97,000 103,000 100,000 104,000 104,200 Crude Oil & NGL (BOE/d) 43 45% of AA 44,000 46,000 44,700 Operating Costs (2) $9.75/BOE $9.25/BOE $8.81/BOE Transportation Expense (2) $3.00/BOE $3.00/BOE $2.89/BOE Cash G&A $2.40/BOE $2.25/BOE $2.19/BOE 1) Based on forward markets at July 22, 2015: US$51.99/bbl WTI, US$2.89/Mcf NYMEX, $2.75/GJ AECO, USD/CDN 1.27 2) Revised by the Marcellus gathering cost reclassification of $1.35/BOE from operating costs to transportation expense 9
Focused Portfolio with Significant Growth Potential 10% of 2015E Production Emerging growth area in the Wilrich and Duvernay 120,000+ net acres in the Wilrich and Duvernay 60 net future drilling locations Long-life, low decline 20% of 2015E Production Large discovered OOIP; 150 future drilling locations and EOR potential Primary, secondary & tertiary recovery potential 2015E Production: Natural Gas 56% Liquids 44% Production split: U.S. 60% Canada 40% Top tier acreage position at Fort Berthold Bakken/Three Forks 270 net future drilling locations 2P Reserves: 145 MMBOE 30% of 2015E Production Top tier gas play 52,000 net acres with 174 net future drilling locations 2P Reserves: 840 Bcf 30% of 2015E Production 10
Fort Berthold Overview Fort Berthold, North Dakota Key Facts Discovered OOIP (1) 22 35 MMbbls/1280 DSU Discovered OOIP (1) 1.4 billion bbls Net Acreage 74,000 acres Average Working Interest ~90% 2P Reserves (2) Contingent Resources (3) Future Net Drilling Locations 2015E Production Q2 2015 Production 123 MMBOE 115 MMBOE 270 wells (84 P+PUDs, 186 CR) 27,000 BOE/day 27,100 BOE/day 2015 Focus Continue to improve capital and operational efficiencies Optimize completion design Bakken Three Forks Drilling/ WOC 1) Operated acreage only 2) Gross working interest at Dec 31, 2014 3) Best estimate contingent resources at Dec 31, 2014 11
Fort Berthold Concentrated Core Position & Room to Run The Core represents ~10% of the basin ND Acreage Quality Avg Long Lateral s Peak Monthly Production By Township ND Drilling Density Total Wells per Township Lower well density in our operated townships Significant running room Enerplus has taken a measured approach to: Optimize completions Define the resource Manage financial risk CORE FLANKS Enerplus operated townships MARGINAL CORE MARGINAL INNER CORE CORE CORE INNER CORE Enerplus operated townships CORE FLANKS MARGINAL CORE MARGINAL INNER CORE CORE INNER CORE CORE CORE CORE 12
Barrels of Oil North Dakota Well Performance vs Peers Acreage position and completion design driving best in basin well performance 140,000 Average First 6 Months Cumulative Oil Production per Well All long lateral wells in North Dakota brought on stream since July 2013 (1) 120,000 100,000 80,000 60,000 40,000 20,000 0 Enerplus Peer 1 Peer 2 Peer 3 Peer 4 Peer Avg Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 1) Wells with a completed interval greater than 6,000 ft 2) Peers include: Continental, EOG, Halcon, Hess, Marathon, Newfield, Oasis, QEP, SM Energy, Whiting and WPX 3) Production data comprises all long horizontal wells in North Dakota with first production from July 2013. Data sourced from North Dakota Industrial Commission 13
Cumulative oil (bbls) Fort Berthold Improving Productivity through Completion Design Cumulative oil (bbls) Bakken 2 Mile Laterals Three Forks 2 Mile Laterals 500,000 450,000 400,000 1200 Mbbls 900 Mbbls 600 Mbbls 2013 & 2014 High Volume Completions 2012 Completions 500,000 450,000 400,000 1200 Mbbls 900 Mbbls 600 Mbbls 2014 2nd Bench TF 2013 & 2014 High Volume Completions 2012 Completions 350,000 350,000 300,000 300,000 250,000 250,000 200,000 200,000 150,000 150,000 100,000 100,000 50,000 50,000 0 0 2 4 6 8 10 12 14 16 18 20 22 24 Months 0 0 2 4 6 8 10 12 14 16 18 20 22 24 Months 14
Fort Berthold Improving Capital Efficiencies Cap Efficiency ($K/BOE/day) Reduction in well costs and large increase in IP rates driving top quartile capital efficiencies (1) $25,000 $20,000 $19,500 $15,000 $17,000 $15,500 $10,000 $11,500 $10,500 $7,500 $5,000 $0 Year 2012 2013 2013 2013 2013 2014 Proppant Ceramic Ceramic White Sand White Sand White Sand White Sand Stages 23-29 28 28 35-38 36-42 36-42 lbs/ft 275 325 750 750 1,000 1,000 1) Capital efficiency based upon 30 day initial production rates and total well costs 15
Barrels of Oil per day New Completion Design Driving Outperformance Recent high pump rate, high volume completions driving outperformance in lower EUR areas Fort Berthold Recent Completions - IP 30 Rates 1,800 1,600 1,400 1,200 1,000 1,706 bbl/d (Bakken) 1,616 bbl/d (Bakken) 1,500 bbl/d (Bakken) 1,360 bbl/d (Three Forks) 1,205 bbl/d (Three Forks) 1,130 bbl/d (Bakken) 38 41 Stages White Sand 1,000 lbs/ft Higher pump rate 800 600 400 600 Mbbl Type Curve 200 0 0 30 60 90 120 150 180 210 240 270 300 330 360 Days Cactus Pad Bikes / Native Dwellings Pad 16
IRR (Pretax) Monthly Oil Production (Mbbl) Fort Berthold Economics 50 40 30 Fort Berthold Type Curves 1,200 Mbbl Type Curve 900 Mbbl Type Curve 600 Mbbl Type Curve 2014 & 2015 Onstreams Avg 20 10 0 175% 150% 125% 100% 75% 50% 25% 0% 0 10 20 30 40 50 60 Months IRR Sensitivity $40 $50 $60 $70 $80 WTI (US$/bbl) 1) 2014 & 2015 onstreams based on peak calendar month 2) Based on drill, complete, tie-in and facilities cost of US$10MM 3) Sales point differentials to WTI : 2015 2017 -US$9.50, 2018 & beyond -US$7.50. Based on flat NYMEX Gas price of US$3.25/mcf 17
Our Competitive Advantage Focused portfolio with significant future drilling inventory Demonstrated track record of delivering profitable growth in production, reserves and funds flow Strong operational capability with disciplined capital allocation and focus on improving capital efficiencies Prudent financial strategy & balance sheet management Attractive valuation and yield 18
Investor Relations Contacts Drew Mair Manager, Investor Relations 403-298-1707 dmair@enerplus.com Krista M. S. Norlin Sr. Investor Relations Analyst 403-298-4304 knorlin@enerplus.com 1-800-319-6462 investorrelations@enerplus.com www.enerplus.com The Dome Tower Suite 3000, 333 7th Ave SW Calgary, AB Canada T2P 2Z1 19
Supplemental Information
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Debt Composition at June 30, 2015 Debt Composition Senior Notes Maturities (1) Bank Credit Facility - $1 billion 11 banks in Enerplus bank credit facility Unsecured, covenant-based with current borrowing rate of less than 3% Credit facility matures October 31, 2017 Senior Unsecured Notes - CDN$1,041 MM Notes are rated NAIC 2 and rank equally with bank credit facility; weighted average interest rate of 5.2% $ millions Undrawn Amount $920MM Senior Notes $1,011MM (1) $30MM (2) 180 160 140 120 $163 $145 $145 $138 $138 100 $86 Drawn Bank Facility $80MM 80 60 40 20 0 $14 $0 $56 $56 $50 $50 1) Canadian dollar equivalent of U.S. dollar denominated notes translated at June 30, 2015 FX rate of USD/CDN 1.2474 2) Canadian dollar denominated notes 21
2015 Funds Flow Sensitivities 2015 Sensitivities Est. effect on 6 mos. 2015 Funds Flow ($ Million) Est. effect on 6 mos. 2015 Funds Flow per Share ($/share) Change of US$5.00/bbl WTI crude oil $29 $0.14 Change of US$0.50/Mcf NYMEX natural gas $16 $0.08 Change of 1,000 BOE/day production for rest of year $3 $0.01 Change of $0.01 in the USD/CDN exchange rate $2 $0.01 2015 Differential Outlook: * Mixed Sweet Blend (MSW) Western Canada Select (WCS) U.S. Bakken Marcellus Basis US($5.00)/bbl US($13.00)/bbl US($9.50)/bbl US($1.25)/Mcf * Before field transportation costs. Compared to US$ WTI crude oil and US$ NYMEX gas. The sensitivities above are based on forward markets as at July 22, 2015, approximately 206.2 million outstanding shares, and a foreign exchange rate of 1.27 USD/CDN. 22
Crude Oil Hedging Summary Q3 2015 Q4 2015 1H 2016 2H 2016 Hedge position as % of forecasted production (1) Hedged Unhedged 75% 25% 55% 45% 66% 34% 66% 34% Volume (bbl/d) Price (US$/bbl) Volume (bbl/d) Price (US$/bbl) Volume (bbl/d) Price (US$/bbl) Volume (bbl/d) Price (US$/bbl) Swaps 8,000 $93.86 12,500 $82.10 3,000 $64.28 - - Upside Collars Sold Puts 4,000 $62.23 (2) 4,000 $62.23 (2) - - - - Purchased Calls 4,000 $93.00 (2) 4,000 $93.00 (2) - - - - 3 Way Collars Sold Puts - - 2,000 $48.00 8,000 $50.13 (2) 11,000 $49.34 (2) Purchased Puts - - 2,000 $63.00 8,000 $64.38 (2) 11,000 $64.35 (2) Sold Calls - - 2,000 $70.00 8,000 $79.38 (2) 11,000 $80.09 (2) 1) Forecasted net production volumes after royalties and production taxes, based on annual average production of 100,000 104,000 BOE/day for 2015 and 2016 2) Weighted average volume and price 3) All prices are WTI 23
Natural Gas Hedging Summary Q3 2015 Q4 2015 FY 2016 Hedge position as % of forecasted production (1) Hedged 43% 57% 62% 38% 9% Unhedged 91% Volume (Mcf/d) Price (US$/Mcf) Volume (Mcf/d) Price (US$/Mcf) Volume (Mcf/d) Price (US$/Mcf) Swaps 155,000 (2) $3.73 (2) 101,739 (2) $3.97 (2) Upside Collars Sold Puts 5,000 $3.25 5,000 $3.25 Sold Calls 5,000 $5.00 5,000 $5.00 Purchased Calls 5,000 $4.29 5,000 $4.29 3 Way Collars Sold Puts 25,000 $2.50 Purchased Puts 25,000 $3.00 Sold Calls 25,000 $3.75 1) Forecasted net production volumes after royalties and production taxes, based on annual average production of 100,000 104,000 BOE/day for 2015 and 2016 2) Weighted average volume and price 3) All prices are NYMEX 24