North Dakota's Best-Selling Oil and Natural Gas Strategy for 2013

Transcription

1 Investor Update The Game Plan April 2013 Forward Looking Information Advisory FORWARD-LOOKING INFORMATION AND STATEMENTS This presentation contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", guidance, "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", 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: Enerplus' asset portfolio; future capital and development expenditures and the allocation thereof among our resource plays and assets; future development and drilling locations, plans and costs; the performance of and future results from Enerplus' assets and operations, including anticipated production levels, expected ultimate recoveries and decline rates; future growth prospects, acquisitions and dispositions; the volumes and estimated value of Enerplus' oil and gas reserves and contingent resource volumes and future commodity price and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; the volume and product mix of Enerplus' oil and gas production; the amount of future asset retirement obligations; future funds flow and debt-to-funds flow levels; potential asset sales; returns on Enerplus' capital program; Enerplus' tax position; sources of funding of Enerplus capital program; and future costs, expenses and royalty rates. The forward-looking information contained in this presentation reflect several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' 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 Enerplus' reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements as needed; and the extent of its liabilities. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information and 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 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 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; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in Enerplus' Annual Information Form and Form40-F described at the end of the presentation). The forward-looking information contained in this presentation speak only as of the date of this presentation, and none of Enerplus or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws. 1

2 Corporate Strategy Improve the profitability and sustainability of our business: Enhance our focus through disciplined return-based capital allocation and active management of asset portfolio Improve cost control and operational efficiency Preserve our financial strength Deliver growth in reserves and production through development of top tier growth plays and more mature, foundation assets Provide a combination of growth and income to investors Plans Improve capital efficiencies by reducing drilling and completion costs and improving operational execution Sell non-core assets to improve focus of portfolio, fund further portfolio development and preserve financial strength Continue to develop and grow production at Fort Berthold, Canadian waterfloods, Marcellus Modest appraisal activities in the Wilrich, Duvernay and Montney Maintain the dividend and deliver growth in cash flow 3

3 Financial Strength and Improving Sustainability 230% Significant improvement in sustainability with lower capital spending, improved costs and dividend reduction 210% 212% Adjusted Payout Ratio 190% 170% 150% 130% 110% 90% 144% 174% 165% 130% 125% Significant value creation from A&D activity has: supported capital investment and dividend preserved balance sheet Debt to cash flow ratio remains reasonable at under 2.0x Senior notes account for 75% of long term debt 70% 50% E* APO without Net A&D or DRIP/SDP Proceeds APO including Net A&D and DRIP/SDP Proceeds Expect to manage cash flow shortfall through non-core asset sales and additional cost reductions * 2013E APO related to 2013 original budget and excludes A&D activity. 4 Compelling Asset Portfolio Balanced portfolio of oil and gas in both Canada and the US 45% crude oil, 5% nat gas liquids 63% light oil 50% natural gas 60% Canada / 40% US Resource play focus with significant growth potential Crude Oil - Bakken IOR/EOR in mature oil assets US Natural Gas - Marcellus Canadian liquids rich natural gas: Stacked Mannville Duvernay Montney Low decline, cash generating assets High working interest ~24% average corporate decline rate 5

4 2013 Capital Allocation Reduced capital spending by 20% US Gas - Marcellus 12% Cdn Gas 12% Cdn Oil - Waterfloods 23% Other 4% US Oil - Bakken 49% ~75% directed to crude oil projects Continued focus in Fort Berthold, Canadian waterfloods and Marcellus Modest delineation in the Duvernay, Wilrich and Montney Average annual production expected to increase by 2% Crude production expected to increase by 2.5% 6 Delivering Organic Growth Total Production Oil and Liquids Production MBOE/day Q Q Q Q Q Q Q Q to AA Guidance 84 to Exit Guidance MBOE/day Q Q Q Q Q Q Q Q AA Guidance 2013 Exit Guidance Oil & Natural Gas Liquids Natural Gas Crude Oil Liquids 7

5 Compelling Reserves Growth Total Reserves* Crude Oil Reserves* 400 7% growth in % growth in 2012 MMBOE MMBOE 322 MMBOE 306 MMBOE 47% 43% 40% MMbbl MMbbl 171 MMbbl 192 MMbbl % 53% 55% Liquids Crude Oil Natural Gas Crude Oil * Based on 2P company interest reserves at December Competitive Reserve Addition Costs $/BOE $45 $40 $35 $30 $25 $20 $15 Finding and Development Costs $39.04 $36.71 $17.22 $26.26 $14.88 $ Highlights: Continued trend of improving F&D costs - down 8% in % of reserve additions were from oil properties Replaced 283% of 2012 oil production $10 $5 $ F&D* 2011 F&D* 2012 F&D* Acquisition and divestment activity had a positive impact, resulting in FD&A of $22.92/BOE including FDC Excl. Future Development Capital Incl. Future Development Capital * Based on 2P company interest reserves at December 31 9

6 Future Growth Potential MMBOE Total contingent resources of 364 MMBOE would more than double existing reserves 346 MMBOE 51 MMBOE (304 Bcf) 89 MMBOE (533 Bcf ) 105 MMBOE 101 MMBOE US Gas Canada Gas US Oil Canada Oil 364 MMBOE 223 MMBOE (1.3 Tcf) 47 MMBOE (283 Bcfe ) 34 MMBOE 60 MMBOE P Reserves 2012 Economic Contingent Resources US Crude Oil - Fort Berthold: > 130 future net operated drilling locations to support reserves and contingent resource Canada Crude Oil: Incremental recovery and enhanced oil recovery potential in 9 waterflood fields US Natural Gas Marcellus Shale: 1.3 Tcf of contingent resource Top tier non-operated land position in northeast Pennsylvania Canada Natural Gas Wilrich Growing Deep Basin potential with 283 Bcfe of contingent resource Unquantified upside (not included in contingent resource): ~120,000 net acres in Montney and Duvernay Operated Marcellus Other oil prospects 10 Delivering Funds Flow Growth Funds flow driven by 25% increase in crude oil production from 2011 to 2013E Expect funds flow growth and improvement in adjusted payout ratio in 2013 Balance sheet remains strong Estimated debt to funds flow ratio of <2.0x at YE

7 2013 Cash Flow Protection 70% Crude Oil Hedge Positions* 64% 70% Natural Gas Hedge Positions* 60% 60% % of net after royalty production 50% 40% 30% 20% 10% 0% Hedged at $100.44/bbl 13% Hedged at $92.56/bbl % of net after royalty production 50% 40% 30% 20% 10% 0% 34% 8% at US$ % at $ % at $ % 6% at US$ % at $ % at $ % US$4.12 1H H WTI Swaps AECO Puts AECO Swaps NYMEX Swaps * As of March 26, 2013, Based on weighted average price (before premiums), average annual production of 82,000 85,000 BOE/day for 2013, less royalties of 21%. 12 Attractive Valuation Enerplus (2) Canadian Competitor Average (2) (Range) U.S. Competitor Average (3) (Range) 2013E Price/CF 4.6x 7.2x (2.8x 10.4x) 2013E EV Multiple (1) 6.3x 8.8x ( x) 2013E EV per Daily BOE $52,200 $86,250 ($50,700 $151,100) 2013E Debt to Cash Flow 2.1x 2.1x (1.0x 3.5x) Yield 7.3% 7.0% (2.7% %) 6.3x (3.8x 12.8x) 7.3x (4.8x 13.7x) $139,000 ($85,000 $194,500) 1.7x (0.9x 2.9x) 0.1% (0% - 0.6%) (1) Canadian Peers calculated using EV/DACF incl. hedging. US Peers calculated using EV/EBITDAX (2) RBC Capital Markets research dated March 31, Peer group includes ARC, Baytex, Bonavista, Crescent Point, Pengrowth, Penn West, PetroBakken and Peyto. RBC Pricing Assumptions: WTI 2013 US$91.00/bbl; AECO 2013 CDN$3.40/Mcf; 2013 US$/CDN$1.00 (3) RBC Capital markets research dated March 28, Peer group includes Oasis, Kodiak, Continental, Whiting, Range and EOG. RBC Pricing Assumptions: WTI 2013 US$91.00/bbl; NYMEX US$3.75/Mcf 13

8 Why Enerplus? Financial strength and improving sustainability Improving cost structures, capital efficiencies and focus Delivering attractive reserve, production and funds flow growth Compelling assets in Canada and U.S. Low decline asset base with significant inventory of early stage opportunities to deliver future growth in reserves and production Compelling dividend Current yield of ~7.5% Attractive valuation relative to asset value and peers Upside exposure to improving natural gas prices with growing NYMEXbased natural gas production 14 Asset Review: Crude Oil

9 Top Tier Light Oil Play in North Dakota Current Operated and Non-Operated Locations Key Facts OOIP MMbbls/1280 DSU Net Acreage (90% WI) ~69,000 (108 sections) 2012 P+P Reserves 86.1 MMBOE 2012 Contingent Res. Est MMBOE Future Drilling Locations 2013E Average Production >130 (2P & CR) 16,000 BOE/day Concentrated land position in North Dakota Dunn & McKenzie counties Prospective for Bakken and Three Forks throughout entire acreage positions Average ~90% operated working interest 5 7 years drilling inventory at current pace 16 Delivering Organic Oil Growth at Fort Berthold BOE/day 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 - Production growth of ~120% in AA Guidance 2013 production expected to grow over 30% averaging 16,000 BOE/day Expect to drill and complete net wells Over 90% of drilling expected to be long horizontal wells (2/3 Bakken, 1/3 Three Forks) Focused on improving costs and efficiencies Rates for completion and other services falling Increased pad drilling expected to result in lower drilling days Evaluating optimal well spacing 17

10 Cost Effective Reserves Growth at Fort Berthold Total 2P reserves have nearly quadrupled since 2010 at Fort Berthold MBOE 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, Proved Developed Producing Proved Developed Not Producing Proved Undeveloped Probable 86.1 MMBOE at end of 2012, up 53% from YE 2011 Added 34.2 MMBOE of reserves at F&D cost (incl. FDC) of $25.38/BOE 50% proved with 83 net PUD locations 2012 recycle ratio of 2.0 times 33.5 MMBOE of assessed contingent resources at Fort Berthold at end of MMBOE in the Bakken 21.4 MMBOE in the Three Forks 18 Fort Berthold Long HZ Well Performance Well results in line with expectations wells Early well performance last year impacted by experimentation in frac design to reduce costs Improved performance with return to original frac design 8 9 wells * Production data as of April 8,

11 Fort Berthold Economics (long lateral wells) The range of EURs is dependant upon zone (Bakken or Three Forks) and well density. Budgeted Economics* ( Mbbl EURs) Well Costs $12.9 million Projected IRR 17% 44% Break-Even Cost WTI US$55 $75/bbl NPV per well (10%) $2.7 - $12.3 million Sensitivity ( Mbbl EURs) Well Costs (15% reduction from budget) $11 million Projected IRR 23% 60% Break-Even Cost WTI US$50 $65/bbl NPV per well (10%) $4.5 - $14 million *Well costs reflect drill, complete and tie-in. Economics based on US$90 WTI constant price (10,000 ft depth, 9600 ft lateral extensions, 29 frac stages, high strength ceramic proppant) 20 Fort Berthold Well Spacing (1280 acres per drill spacing unit) 2P + CR (EUR) Potential Upside Middle Bakken Middle Bakken???? Lower Bakken Lower Bakken Three Forks Three Forks??? Estimated Recovery: 2.7 million bbls/dsu 12-16% recovery factor 33.5 MMBOE CR estimate assumes land utilization of: Bakken 90% Three Forks 75% 86.1 MMBOE 2P Reserves: only 13% of DSU s booked to 4 wells/dsu include 83 net PUD locations and 74 net developed producing wells Estimated Recovery: 3-4 million bbls/dsu up to 18% recovery factor Bakken OOIP: Three Forks OOIP: 9 12 million bbls/dsu 8 10 million bbls/dsu 21

12 Excess Takeaway Capacity in North Dakota ~20% of our US Bakken production transported on rail in 2013, ~80% through pipelines ~10% is exposed to LLS pricing Forecast differentials of $12.00 in 2013 Excess takeaway capacity 22 Consolidating Ownership at Sleeping Giant Key Facts 2012 P+P Reserves 30.5 MMBOE Current Production 7,300 BOE/day 90% Operated Working Interest 90% operated working interest Over 400 million barrels of original oil in place 8% recovery to date Low decline of ~14% Opportunities for optimization, refracs and limited infill drilling Evaluating waterflood and EOR potential Significant free cash flow 2013E netback of $50/BOE 23

13 Focusing our Asset Portfolio: Sleeping Giant Purchase vs. Manitoba Asset Sale (Based on internal evaluations and pricing at time of transaction) Sleeping Giant Purchase Manitoba Sale Purchase Price [$M] $118,000 $218,000 Working Interest [%] 90% 52% Funds flow multiple $/Boepd $84,000 $142,000 $/boe [2P] $20.85 $23.34 $/boe [2P incl FDC] $23.00 $37.76 Production [boepd] Base Decline [%] 14.0% 12.5% % Oil weighting 80% 100% Watercut current [%] 14% 95% Avg. Productivity Per Well [bopd] RLI [2P] NOI 2P [$M] $30,133 $27, Forecast Netback $48.88 $53.08 Recycle Ratio [2013 Netback/FD&A] Op Costs [$/boe] $5.61 $14.32 Royalty % of Revenue [%] 17.7% 11.7% Field Vintage (Year of discovery) Recovery to date ~8% ~21% Continuing to focus on core areas with better operating metrics 24 Low Decline Canadian Crude Oil Assets Growth potential with low average decline rate of ~12% 22% of total production High working interest ownership of over 90% Significant free cash flow Over 1.2 billion barrels original oil in place with 22% recovered to date 60.3 million barrels of contingent resource from EOR and IOR potential 2 polymer projects underway Over 150 contingent resource drilling locations to unlock value 25

14 2013 Canadian Oil Capital Program 2013E Capital by Waterflood Prospect 2013E Capital Spend Allocation Pembina 5 Way 9% Other 13% Med Hat Glauc C 25% Plant & Facilities 42% Brooks 9% Giltedge 10% Pouce Coupe 11% Freda Lake/Neptune 23% Drilling & Completions 58% 26 Defining the IOR/EOR Opportunity 2012 YE 2P Reserves (MMBOE) Contingent Resource (MMBbl) Asset 2013E Production (BOE/day) OOIP (net) (MMBbl) Total Recovered (MMBbl) IOR EOR Total Total Recoverable 2013 Net Operating Income Medicine Hat, AB 4, % ~$42/BOE Giltedge, AB 1, % ~$38/BOE Freda/Skinner Lake/Neptune, SK 3, % ~$48/BOE Brooks 3, % ~$28/BOE Cadogan, AB % ~$46/BOE Kingsford % ~$42/BOE Pouce Coupe % ~$23/BOE Sub-Total 14, Other Canadian Oil properties without Contingent Resources: Asset 2013E Production 2012 YE 2P Reserves (MMBOE) 2013 Net Operating Income Pembina 5 Way 1, ~$27/BOE Joarcam 1, ~$12/BOE Progress ~27/BOE 27

15 Waterflood Success Story - Medicine Hat Glauc C Key Facts OOIP 224 MMBbls Recovery Factor to Date ~9% Cumulative Production ~19 MMBbls P+P Reserves (Dec 31, 2012) 21.1 MMBOE Polymer Project Area Best Estimate Contingent Resource (Dec 31, 2012) Oil Quality 2013E Avg. Production IOR 1.5 MMBOE EOR 22.4 MMBOE 11 to 18 API 4,470 BOE/day 66% reinvestment over past 5 years has grown production by over 60% Polymer project has estimated incremental recovery of 10% (22.4 MMBOE) Improved waterflood management has estimated incremental recovery of 3% (1.5 MMBOE) 72% WI across ~14 sections 28 Medicine Hat Glauc C Production Average Daily Production (BOE/day) 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, ~60% growth achieved over 5 years with ~65% reinvestment Jan 2008 May 2008 Sep 2008 Jan 2009 May 2009 Sep 2009 Jan 2010 May 2010 Sep 2010 Jan 2011 May 2011 Sep 2011 Jan 2012 May 2012 Sep 2012 Jan 2013 Implemented new waterflood development strategy in 2009 Numerous battery upgrades from Moved to 100m inter-well spacing May 2012 polymer pilot injection 29

16 Asset Review: Natural Gas Marcellus: Reduced Spending on Dry Gas Bradford/Sullivan Counties 40% of 2013 Marcellus capital budget Susquehanna/Wyoming Counties 25% of 2013 Marcellus capital budget Lycoming County 20% of 2013 Marcellus capital budget 44,000 net non-operated acres with an approximate 20% working interest Major non-op partners are EXCO and Chief $80 million capital budget for 2013 Expect majority of core non-operated acreage retained by end of year EXCO Resources Chief O&G & Chesapeake 31

17 Delivering Growth in the Marcellus Production Mcf/day 70,000 60,000 50,000 40,000 30,000 20,000 10,000 - Reserves Bcf ~100% growth in AA Guidance annual production guidance of ~65,000 Mcf/day (60% growth) Exit 2013 guidance of ~75 MMcf/day Average production guidance estimates Marcellus gas represents ~25% of expected 2013 corporate natural gas production 2012 proved plus probable reserves increased by 46% to 225 Bcf Accounts for 27% of corporate 2P natural gas reserves 1.3 Tcf of best estimate contingent resource 32 NE Pennsylvania Well Performance Wells in top tier acreage significantly outperforming type curve Susquehanna Bradford 8 Bcf E Lycoming 6 Bcf W Lycoming * Production data as of April 9, Well counts shown are on a gross basis. 33

18 Marcellus Economics 50.00% 45.00% $ $2.90/Mcf breakeven in Bradford & Susquehanna with Bcf type wells 40.00% $5 Gas 35.00% Rate of Return 30.00% 25.00% 20.00% 15.00% $4 Gas 10.00% 5.00% $3 Gas 0.00% EUR (bcf) * Returns assume well cost of $7.0 million 34 An Abundance of Deep Gas Opportunity Stacked Mannville 71,000 net acres of land (54,000 net acres of land in the Wilrich, majority 100% WI) Montney 34,000 net acres of undeveloped land, 100% WI Approximately 188,000 net acres of high working interest land Significant potential in Wilrich, Duvernay and Montney ~1000 potential future drilling locations Successful drilling results to date in Wilrich Joint venture potential in Duvernay & Montney Duvernay 83,000 net acres of undeveloped land, 100% WI 35

19 Deep Gas Wilrich Key Facts Key properties Net Acreage (acres) Future HZ Drilling Locations Est. EUR/Well Ansell, Minehead, Hanlan ~54,000 acres (84 sections, majority 100% WI) Over Bcfe 2012 Contingent Res. Est. 283 Bcfe - 57 net drilling locations 2013 capital program of ~$40 million focused primarily in Ansell Plan to drill 2 to 5 wells Breakeven cost of <$2.00/Mcf Contiguous land blocks in highly prospective regions Enerplus working interest lands 36 Wilrich Positive Drilling Results 5.0 Bcf Well 6.0 Bcf Well AECO ($/Mcf) IRR % Pay out (Yrs) NPV 10% ($MM) IRR % Pay out (Yrs) NPV 10% ($MM) $ $ $ Capital* $7.1 million $7.1 million 30 Day IP 5,300 Mcf/day 6,000 Mcf/day Liquids 7 bbls/mmcf 7 bbls/mmcf BESC $1.93/Mcf $1.61/Mcf Cumulative Production (MMcf) 1,600 1,400 1 Well 2 Wells 1,200 1, Wells Months Producing Average Actual Production 6.0 Bcf Type Curve Type curves are based on offset data and are supported by our well results 5.0 bcf Type Curve * Capital assumes pad drilling 37

20 Duvernay: Emerging Top Quality Liquids-Rich Resource Play Key Facts Key Properties Net Acreage Est. OGIP Est. Density Est. EUR/Well Est. Initial Hz Well Cost Est. 30 day IP Est. Avg. Liquids* Willesden Green, AB ~83,000 acres (130 sections, 100% WI) ~65 Bcf/section 4 wells/section 3.5 Bcf ~$15 million ~4.4 MMcf/day bbls/mmcf Analogous rock characteristics to the Eagleford Prolific over-pressured Devonian source rock (~56 MPa) Increased industry activity in Willesden Green region providing strong geological control and increased confidence in play Equivalent thermal maturity and depth to proven liquids-rich Kaybob area 4 well/section development provides us with over 400 future Hz drilling locations One vertical strat well drilled in late 2012 results confirm liquids rich window Vertical delineation planned in 2013 to better define optimal liquids window for future development * Actual wells may yield higher or lower liquids ratio than the average range 38 Duvernay Shale Willesden Green Enerplus 39

21 Montney Cameron/Julienne Creek Key Facts Key Properties Net Acreage Estimated OGIP Future Hz Drilling Locations Cameron/Julienne Creek ~33,000 acres (+50 sections, 100% WI) 150 Bcf/section 500+ Montney Vert. Test Well and Hz Licensed Wells North Montney Regional Pool Est. EUR/Well Bcfe 3D seismic purchased and reprocessed Existing well and vertical test well indicate approximately 300 metres of Montney thickness Rock analysis indicates good reservoir development Enerplus vertical testing upper and lower Montney: Drilled to 2,400 metres, positive gas tests that support type curve 40 Upper Montney Type Curve Economics 4.0 Bcf Well 5.0 Bcf Well 6.0 Bcf Well AECO ($/Mcf) IRR % Payout (Years) NPV 10% ($MM) IRR % Payout (Years) NPV 10% ($MM) IRR % Payout (Years) NPV 10% ($MM) $ $ (0.1) $ (2.2) (1.1) (0.0) Capital $6.2 million $6.2 million $6.2 million 30 Day IP 3,700 Mcf/day 4,600 Mcf/day 5,500 Mcf/day Liquids bbls/mmcf bbls/mmcf bbls/mmcf BESC $3.05/Mcf $2.34/Mcf $2.01/Mcf Type curves are based on wells in the North Montney trend (Town & Blair) and are supported by our vertical Montney test well Capital assumes pad drilling 41

22 Supplemental Information The Game Plan Corporate Profile Ticker Symbol (TSX & NYSE) ERF Enterprise Value (1) $3.9 billion Average Daily Trading Value (Q1 2013) $24 million 2013E Average Daily Production 82,000 85,000 BOE/day 2013E Exit Production 84,000 88,000 BOE/day Oil and Liquids Weighting ~50% 2013E Capital Spending $685 million Oil and Liquids Plays ~85% 2013E YE Debt to Trailing 12 Months Funds Flow <2.0x 1. Market Cap. at April 11, 2013 plus December 31, 2012 net debt of $1.1 billion 43

23 Commitment to Dividend Model Investor Composition As of January 31, % 50% 13% US/Intl Institutional Canadian Institutional US/Intl Retail 18% Capital markets place higher valuation on dividend paying energy companies Canadian energy yield companies trading at ~2.2x EV/DACF and ~2.2x cash flow multiple premiums to senior Canadian and US energy names* Investor composition supports dividend model ~70% of shares are held by retail investors Have no plans to adjust monthly dividend Sale of non-core assets, improvement in natural gas prices and reduced capital spending improving sustainability * RBC Capital Markets, March 27, Guidance Overview E Change Capital Expenditures ($millions) $853 $685-20% Annual Average Production (BOE/day) 82,098 82,000 85,000 +2% Exit Production (BOE/day) 85,800 84,000 88,000 - Oil & Liquids Weighting 49% 50% +1% Debt to Funds Flow Ratio 1.7x <2.0x - Adjusted Payout Ratio* 174% 125% -49% Cash Operating Costs($/BOE) $10.53 $ % Cash G&A Costs ($/BOE) $2.61 $ % Royalties 20.5% 21% - * Adjusted payout ratio is calculated as the sum of dividends paid to shareholders, net of participation in the Stock Dividend Plan, plus capital expenditures divided by funds flow. 45

24 2013 Capital Budget Pricing and Sensitivities 2013 Forward Prices as of Feb 7, 2013 Oil - WTI (US$/bbl) $97.06 Gas NYMEX (US$/Mcf) $3.51 Gas AECO ($/Mcf) $ Sensitivities as of Feb 7, 2013* Est. effect on 2013 Funds Flow ($ million) Change of $5.00/bbl WTI crude oil $24 Change of $0.50/Mcf natural gas $32 Change of 1,000 BOE/day production $10 Change of $0.01 in the US$/CDN$ exchange rate $10 * The sensitivities above reflect our forecasts, outstanding commodity contracts, and are based on forward markets as at February 7, Production Composition and Differentials 2013E Production 2013E Crude Oil Composition US Gas 16% US Oil 24% Canada Heavy 25% Canada Gas 34% Canada Oil 22% Canada Medium 12% Canada Light 11% US Light 52% NGLs 4% 2013 Estimated Price Differentials to WTI Original Current Guidance Forecast* US Light US$13.25 US$12.00 Canada Light US$13.00 US$9.00 Canada Medium US$16.00 US$14.00 Canada Heavy US$21.00 US$30.00 * February 2013 estimates 47

25 Debt Composition Debt Maturities* Senior Notes US$742MM & CAD$70MM $700 $600 $585 $500 Unutilized Capacity $739MM $ Millions $400 $300 $200 $100 $46 $46 $91 $45 Bank Debt $261MM $ and beyond ~$1.1 billion outstanding debt as of YE 2012, comprised of: Senior notes rated NAIC 2 and rank equally with bank credit facility Weighted average coupon rate of 5.8% Credit facility is a $1 billion unsecured, covenant based facility maturing 2015 Current drawn pricing of less than 3% * Notional outstanding principal as at December 31, 2012, US$ amounts converted at $1 US/CDN Year End Analysis Change Funds Flow $574 million $644 million +12% Adjusted Payout Ratio * 212% 174% -38% Debt to Funds Flow 1.6x 1.7x - Average Daily Production 75,332 BOE/day 82,098 BOE/day +9% Finding & Development Costs ** $26.26/BOE $24.21/BOE -8% Operating Costs $10.64/BOE $10.23/BOE -4% Proved + Probable Reserves *** MMBOE MMBOE +7% Contingent Resources 485 MMBOE 364 MMBOE -25% Reserve Life Index 9.8 years 10.9 years +11% * Calculated using funds flow. Adjusted payout ratio in %; in %. ** Including future development costs. *** Company interest reserves at December

26 Stock Dividend Program ( SDP ) Benefits: All shareholders are now eligible to participate Shareholders can elect to receive cash dividends or Enerplus shares 5% discount to current market price and no fees or commissions Participation in the SDP is not expected to generate dividend income for Canadian shareholders Generally 100% of the value of the dividends earned by nonresidents used to purchase shares (no withholding tax applied) SDP participation is completely optional 50 Enerplus Share Ownership Investor Composition Geographic Composition Total Retail 69% 19% 13% 18% Total Institutional 31% 38% 50% 62% US/Intl Institutional Canadian Institutional US/Intl Retail Canada US and Other As of January 31, 2013 As of January 31,

27 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), "Mcfe" (thousand cubic feet of gas equivalent), "Bcfe" (billion cubic feet of gas equivalent) and "Tcfe" (trillion cubic feet of gas 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, and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Mcfes, Bcfes and Tcfes. BOEs, Mcfes, Bcfes and Tcfes 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 "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "F&D costs", FD&A costs, recycle ratio and operating netback as measures of operating performance. We calculate funds flow based on cash flow from operating activities before changes in non-cash operating working capital and decommissioning expenditures, all of which are measures prescribed by International Financial Reporting Standards ( IFRS ) and which appear in our Consolidated Statements of Cash Flows. We calculate "payout ratio" by dividing dividends to shareholders by funds flow. "Adjusted payout ratio" is calculated as cash dividends to shareholders plus development capital and office expenditures, divided by funds flow from operating activities. Operating netback is calculated as revenues after deducting royalties, operating costs and transportation. A recycle ratio is calculated as F&D costs divided by operating netback. Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the terms "payout ratio", "adjusted payout ratio", "F&D costs" and FD&A costs 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 GAAP and do not have a standardized meaning prescribed by IFRS. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. Presentation of Production and Reserves Information In accordance with Canadian practice, production volumes and revenues 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 "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument adopted by the Canadian securities regulators ("NI "), being Enerplus' working interest before deduction of any royalties), plus Enerplus' royalty interests in reserves. Company interest reserves" are not a measure defined in NI and do not have a standardized meaning under NI Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2012, which include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI , are contained within our Annual Information Form for the year ended December 31, 2012 ("our AIF") which is available on our website at and under our SEDAR profile at Additionally, the Annual Information Form is 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 EDGAR concurrently with this presentation for more complete disclosure on our operations. 52 Advisories Contingent Resource Estimates This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "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 ultimate recovery rates, economic, 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. 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. All of our contingent resource estimates are economic using established technologies and under current commodity price assumptions used by our independent reserve evaluators. There is no certainty that we will produce any portion of the volumes currently classified as contingent resources. The contingent resource estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered, 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, our Wilrich natural gas properties and a portion of our Canadian crude oil properties as reserves and the positive and negative factors relevant to the contingent resource estimates, see our AIF for the year ended December 31, 2012 (and corresponding Form 40-F) dated February 22, 2013, a copy of which is available under our SEDAR profile at and a copy of the Form 40-F which is available under our EDGAR profile at F&D and FD&A Costs F&D costs presented in this presentation are calculated (i) in 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 future development costs in the year, by the additions to proved reserves in the year, and (ii) 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 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. FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves including net acquisitions in the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves including net acquisitions 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, development and acquisition costs related to its reserves additions for that year. See "Non-GAAP Measures" below. 53

28 Advisories 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, "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, 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 Information Regarding Reserves, Resources and Operational Information above. 54 Investor Relations Contacts Jo-Anne M. Caza Vice President, Corporate & Investor Relations jcaza@enerplus.com Garth Doll Manager, Investor Relations gdoll@enerplus.com investorrelations@enerplus.com The Dome Tower Suite 3000, 333 7th Ave SW Calgary, AB Canada T2P 2Z1 55