Building Value. The Game Plan. Gordon Kerr, President and Chief Executive Officer. Enerplus Analyst Day April 2012

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1 The Game Plan Building Value Gordon Kerr, President and Chief Executive Officer Enerplus Analyst Day April 2012

2 Key Topics Value creation track record Growth and income why we believe it s the right business model Our funding strategy Our assets near-term value creation opportunities and long-term optionality within our portfolio 1

3 Corporate Strategy Own a portfolio of oil and gas resource plays in North America which includes: early stage assets that offer scope and scale as well as future option value producing assets with development opportunity Improve the profitability of our assets and continue to demonstrate our execution capability Delineate prospective resource and strategically monetize a portion to facilitate our growth and income model Pursue strategic acquisitions complementary to the existing portfolio Maintain a healthy balance sheet Committed to yield 2

4 Why We re Committed to Yield Total Return 3 Years (2009 to 2012 YTD) (1,2,3) TSX Energy Index TSX Composite Low Yield TSXCos High Yield TSXCos Low Yield EnergyCos (6%) High Yield EnergyCos 1% 12% 20% 32% 41% High yielding equities generally outperform low yielding, or high growth equities during periods of heightened volatility Total Return 5 Years (2007 to 2012 YTD) (1,2,3) TSX Energy Index TSX Composite Low Yield TSXCos High Yield TSXCos Low Yield EnergyCos High Yield EnergyCos (10%) 0 10% 20% 30% 40% 50% (6%) 6% 11% 15% 45% 85% (30%) 0 30% 60% 90% Dividend investing can be an effective all-weather strategy, and particularly effective in the current stage in the market cycle Demand for dividends supported by investor demographics Total Return 10 Years (2002 to 2012 YTD) (1,2,3) TSX Energy Index TSX Composite Low Yield TSXCos High Yield TSXCos Low Yield EnergyCos High Yield EnergyCos 105% 178% 154% 224% 249% 262% Dividends impose discipline on capital allocation Dividends provide a more direct benefit to shareholders 0% 100% 200% 300% (1) As per Bloomberg as of April 3, 2012 (2) TSXCos are member of the TSX Composite; EnergyCos are members of the TSX Energy Index; equal weighted indexes (3) Includes companies >$1 billion at beginning of period - High Yield Cos currently yield >4.0%; Low Yield Cos currently yield <4.0% Source RBC Capital Markets 3

5 Dividends/Distributions Have Been a Key Component of Shareholder Total Return $91.89/share paid since inception* Paid over $6 billion in cumulative dividends* $5.65 $5.61 $7,000 $5.26 $5.04 $5.04 $4.89 $6,000 $3.68 $3.97 $4.52 $4.29 $4.20 $4.47 $5,000 $2.72 $3.32 $3.29 $2.83 $2.60 $2.58 $3.12 $3.32 $3.25 $2.16 $2.16 $2.16 $4,000 $3,000 CDN $ 000s $1.75 $2,000 $1,000 $0.00 $ Cumulative dividends paid Cash dividends / distributions per share * As of December 31,

6 We Have a Long History of Creating Value for Shareholders Enerplus has delivered a 15.3% per year CAGR since 2000 with dividends reinvested Without reinvestment, CAGR was 12.3% per year $1,200 S&P Oil and Gas Exploration and Production Index S&P 500 Enerplus S&P/TSX Composite Index $1,000 $800 $600 $571 $507 $400 $200 $100 $192 $127 $ * To March 31,

7 The Change in Our Oil Portfolio Proved + Probable Reserves 9% 2011 Contingent Resources Bakken/tight oil reserves have almost tripled 44% 47% 47% 53% Contingent resource now comprised of near-term, high netback oil 192 MMBOE 105 MMbbls Proved + Probable Reserves 25% 19% 16% 253 MMBOE 40% Crude Oil Waterfloods Bakken Oil 2007 Contingent Resources 100% 550 MMbbls Other Conventional Oil Oil Sands All contingent resource associated with oil sands/bitumen capital intensive long lead time to production and cash flow Sold oil sands interests in 2008 & 2010 for $900+ million * As at December 31 6

8 The Change in Our Gas Portfolio Proved + Probable Reserves 2011 Contingent Resources 20% 18% 23% 39% 100% from Marcellus Total natural gas reserves have declined from 1.1 Tcfe to 0.8 Tcfe primarily due to the decline in natural gas prices Proved + Probable Reserves 2007 Contingent Resources Shallow gas now less than 25% of our gas reserves, down from 50% in % 17% 49% No natural gas contingent resources in 2007 Added Marcellus shale gas resource play in superior economics relative to shallow gas Shallow Gas Other Conventional Gas Deep Gas Marcellus Shale * As at December 31 7

9 A More Profitable Oil-Weighted Portfolio Today % 4% 53% Portfolio of resource plays to support organic growth and income Oil & liquids are now 57% of total 2P bookings Oil Natural Gas NGLs Bitumen Light/medium sweet crude oil reserves have increased to 41% of total reserves % 13% 4% 37% Increased oil weighting from our key resource plays Tight Oil: 10% in 2007 to 26% at year-end 2011 Waterfloods: 23% in 2007 to 28% at year-end 2011 * As at December 31 8

10 BOE/day Delivering Organic Production Growth 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, Exit 2011 AA 2011 Exit 2012 AA 2012 Exit Oil and liquids production growing to 50% of total in 2012 oil production growth of 22% natural gas production flat Production growth concentrated in: Tight Oil ~45% growth with netback of ~$50/BOE Waterfloods ~ 3% growth with netback of ~$48/BOE Oil Gas 9

11 MMBOE 175% Organic Reserve Replacement in P reserves increased by 5% MMBOE 47% 322 MMBOE 43% Replaced 300% of our oil production, growing 2P oil reserves by 14% NPV of reserves increased by 10% in 2011 due to increased weighting of oil in portfolio % P Reserves* 57% P Reserves* NPV of Fort Berthold oil property up 160% due to success of drilling program Crude Oil and Liquids Natural Gas * Company interest reserves 10

12 $/BOE Attractive Reserve Additions $30 $25 $20 $15 $17.22 $26.26 $ % of reserve additions from oil and liquids FD&A costs reflect the value captured in the sale of the Marcellus interests for $580 million $10 $5 $8.57 F&D costs attractive despite $150 million of capital that did not add reserves in 2011 $ F&D* 2011 FD&A* Excl. FDC Incl. FDC * Based on 2P company interest reserves at December 31,

13 $/BOE $/BOE Competitive Finding & Development Costs F&D Cost/BOE (1) FD&A Cost/BOE (1) $30 $25 $20 75% Oil* 83% Oil* $26.26 $ % Oil* $22.68 $25 $20 $15 $17.89 $23.84 $20.32 $15 $10 $10 $5 $5 $0 Enerplus Oil weighted peers All peers $0 Enerplus Oil weighted peers All peers Oil weighted peers includes: Baytex, Crescent Point, PennWest, Petro Bakken All peers includes above as well as: ARC, Bonavista, NAL, Pengrowth, Progress, Vermillion (1) Proved + probable reserves at December 31, 2011 including future development capital * % of 2P reserve additions attributable to crude oil 12

14 Our Portfolio Strategy Abundance of internal growth opportunities within portfolio today - not reliant on acquisitions Significant and sufficient dry gas opportunities Would consider accretive acquisitions of quality assets that are complementary to existing core areas where we have expertise preference to Bakken, Waterfloods or other oil/liquids rich assets Pursuing either joint venture or monetization of a portion of our undeveloped acreage in the Montney, operated Marcellus or Duvernay Proven track record of successful, value creating A&D 13

15 Our People Strategy Maintain an employment proposition that retains and attracts the people we need We believe we re positioned in some of the best resource plays in North America Provide opportunity to develop the talent within our organization Keep compensation competitive, performance based and aligned with shareholders interests High visibility to our cultural values both internally and externally 14

16 CAD$/GJ Natural Gas Price Outlook $12.00 $10.00 $8.00 Our outlook is more positive than the strip because: Marginal cost of supply is higher Waning capital markets support for natural gas producers Reduction in cash flows won t support on-going investment Continuing coal to gas switching Increased industrial demand Increasing potential for North American export $6.00 $4.00 $2.00 $- Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Historical AECO Monthly Index Forward AECO Monthly Index April 10,

17 Our Funding Strategy Currently, we have a strong balance sheet and we have the flexibility to manage our balance sheet Low gas prices are creating funding challenges considering our $800 million capital spending plans this year. Another challenge is that 25% of this spending is directed toward Marcellus gas principally to retain leases The February equity issue and the introduction of a Stock Dividend Program moderate our cash funding shortfall Extending credit capacity with term debt We also plan to manage our debt levels through a number of initiatives over the balance of this year and 2013: monetizing our equity portfolio joint venture and/or sale of a portion of our undeveloped land There could be downward pressure on capital spending and growth rates depending on commodity prices and our progress with respect to these funding initiatives Also, in the event that current realized commodity prices prevail and/or no progress has been made on funding initiatives, there could be downward pressure on dividends 16

18 The Game Plan Funding Strategy Robert Waters, Senior Vice-President and Chief Financial Officer Enerplus Analyst Day April 2012

19 2012 Financial Outlook Enerplus has a $800 million capital development program in 2012 Why such a large capital program? Continue to demonstrate organic growth in production/reserves: Abundance of oil & gas growth opportunities in Enerplus current portfolio 10% organic growth in 2012 AA production from oil & NGLs 22% growth in oil volumes in % weighted to crude oil and liquids rich gas 24% directed to Marcellus dry gas, principally to retain leases Includes delineation of strategic undeveloped land 2012 funds flow estimated at approximately $650 million: Recently adjusted downward due to wider oil price differentials and lower fwd gas prices March 26/12 fwd prices: WTI US$107/bbl, AECO gas $2.25/Mcf, NYMEX gas US$2.67/Mcf 1

20 2012 Financial Outlook (cont d) With funds flow of $650 million, capital spending of $800 million and dividends of $425 million, the cash shortfall in 2012 would be approximately $630 million The February equity issue of $331 million and introduction of a Stock Dividend Program will moderate this cash shortfall Debt-to-funds flow is trending higher by year-end. However, we plan to manage debt over the next 18 months: Monetize equity portfolio Sale or JV of undeveloped land Extend credit capacity through term debt markets Moderate capital spending and accept lower growth targets We have crude oil hedge protection on 62% of our net production in 2012 at an average price of US$96.22/bbl and 22% of our net production in 2013 at an average price of US$102.97/bbl. There are no natural gas price hedges in place at this time. 2

21 Why Raise Equity vs. Dividend Reduction? Equity helped support 2012 capital spending plans (including Marcellus spending to retain leases and delineation of undeveloped acreage). Even a substantial dividend reduction would not cover the shortfall Allowed more time to demonstrate production/reserve growth building on our 2011 success Allowed more time for natural gas prices to recover Defensive strategy if weak natural gas prices prevail longer than expected Not unusual to use equity and debt to fund large growth projects Acknowledges high percentage of yield-oriented investors and importance of dividend Yield continues to support relative valuation of share price 3

22 Yield Continues to Support Relative Share Value Yield Price/ CF EV/EBITDA EV/BOE/day P/Nav Enerplus 11.1% 6.2x 7.9x $64,576 73% BMO Large Cap E&P Yield** 6.0% 7.9x 9.4x $92,381 72% Junior E&P - 6.1x 7.1x $87,234 75% Intermediate E&P - 4.5x 6.3x $51,827 71% Senior E&P 1.6% 5.3x 5.8x $71,222 73% Enerplus has a better market valuation than the average junior, intermediate and senior E&P companies Enerplus has a lower valuation compared to BMO s large cap E&P yield index Source: BMO Capital Markets, April 10, 2012 based on 2012 forecast results ** Includes: ARC, Baytex, Bonavista, Crescent Point, Enerplus, Pengrowth, Penn West, PetroBakken, Peyto, Progress, Trilogy, Vermilion 4

23 2013 Financial Outlook For modeling purposes, we have initially assumed a $800 million capital spending program in 2013 as this spending level is consistent with 2012 Our actual capital budget for 2013 will be determined in the fall and the level will be influenced by commodity prices, debt levels, progress on dispositions and opportunities at that time At this level of capital spending, we would expect to increase average production to 90,000 BOE/day and increase funds flow to approximately $770 million under March 26, 2012 strip pricing Debt-to-funds flow could approach 2 times by year end in the context of the current price environment, however we have plans to manage our debt below this level 5

24 Opportunities to Manage Debt Maintain $1 billion bank facility and extend credit capacity with term debt Target $400 million debentures for 7-12 year terms at rates below 4.5% Replace DRIP with Stock Dividend Program that allows non-canadian shareholders to participate (currently 65% of shareholder base) Canadian only DRIP in 2011 was $52 million. Forecast stock dividend proceeds of $70 million in 2012 (partial year of SDP) and $120 million in Monetize equity portfolio Largest position is 5 million shares of Laricina Energy Last Laricina equity issue was at $42.50/share Enough capital loss carry-forwards to shelter gain on sale Joint venture or sell portion of undeveloped land We have retained advisors to assist in joint venture or sale of portion of undeveloped land Currently focusing on Montney, Duvernay, Operated Marcellus Plan is to monetize $250 $500 million of non-dilutive assets in next 18 months Assets would have minimal impact on production/reserves/cash flow 6

25 2013 Financial Outlook (with non-dilutive asset sales) $250 million in asset sales brings 2013 debt-to-funds flow down to 1.6 times $500 million in asset sales brings debt-to-funds flow to 1.3 times. Non-Dilutive Asset Sales $ millions 2013 Base $250 million $500 million Funds flow $ 770 $775 $785 Development capital (800) (800) (800) Dividends (440) (440) (440) Shortfall (470) (465) (455) Beginning debt $1,150 $1,150 $1,150 Shortfall Stock dividend program (120) (120) (120) Proceeds from asset sales - (250) (500) Ending debt $1,500 $1,245 $ 985 Increase (decrease) in debt $ 350 $ 95 $ (165) Debt-to-funds flow 2.0x 1.6x 1.3x Assumptions: 2013 Pricing at Mar. 26/12 fwd strip pricing WTI US$106.57/bbl, HH Gas US$3.53/Mcf, AECO gas $3.06/Mcf For modeling purposes, we have assumed no asset sales occur in 2012 Does not include working capital 7

26 2013 Financial Outlook - Reducing Capital Spending Assumes 2013 capital spending reduced by $160 million (20%) $ millions 2013 Base 20% Reduction in Capital Spend Funds flow $ 770 $ 755 Development capital (800) (640) Dividends (440) (440) Shortfall $ (470) $ (325) Beginning debt $1,150 $1,150 Shortfall Stock dividend program (120) (120) Proceeds from asset sales - - Ending debt $1,500 $1,355 Increase in debt $ 350 $ 205 Debt-to-funds flow Production AA (BOE/day) AA production growth yoy AA production growth debt adj./share Funds flow growth debt adj./share 2.0x 90, % 1.7% 11% 1.8x 87, % 0.3% 10.5% Assumptions: 2013 Pricing at Mar. 26/12 fwd strip pricing WTI US$106.57/bbl, HH Gas US$3.53/Mcf AECO gas $3.06/Mcf For modeling purposes, we assume no asset sales in either 2012 or 2013 Does not include working capital 8

27 Observations Reducing Capital Spending Despite the 20% reduction in capital spending, funds flow is only marginally lower. In fact, funds flow grows at a healthy 10.5% rate on a debt adjusted per share measure largely on the strength of crude oil spending The spending reduction does not fully impact 2013 results. Due to the timing gap between when expenditures are incurred and when wells come on production, the spending reduction will also negatively impact 2014 production and cash flow results There is a risk that we will lose land value through tenure expiries. In addition, delays in delineating undeveloped land could undervalue our assets and/or understate joint venture or monetization efforts Annual average production decreases from 90,000 BOE/day in the base case to 87,700 BOE/day in the capital reduction case. As a consequence, production growth moderates With the 20% reduction in capital spending, debt-to-funds flow improves from 2.0 to 1.8 times. We would still plan to sell at least $250 million in non-dilutive assets (slide 8) which would improve the ratio further 9

28 Observations Reducing Capital Spending (cont d) Our 2013 capital budget will be determined in the fall. If the current realized commodity prices prevail and/or no progress has been made on JV or asset sales, then there will likely be downward pressure on capital spending A dividend reduction would also be considered in the event that current realized commodity prices prevail and/or no progress has been made on funding initiatives Despite a capital spending reduction, we would expect a cash flow shortfall (or increase in debt) of about $200 million in 2013; would continue to pursue JV/sales Living within cash flow continues to be challenged by: Low gas prices Front-end capital loading on early stage growth assets We expect gas prices to begin recovering in 2013 and are more optimistic than the current forward market The marginal cost of supply is significantly above current price levels Capital market support wanes for natural gas producers Corporate cash flows are not sufficient to support continued investment Continuing coal to gas switching Increased industrial demand Increasing potential for North American export 10

29 The Game Plan Our Assets Ian Dundas, Executive Vice-President and Chief Operating Officer Enerplus Analyst Day April 2012

30 Resource Play Focused Asset Base 2012 AA Production Tight Oil 23% Near-term cash flow growth potential Crude Oil Waterfloods 21% Low decline, free cash flow generation Marcellus Shale Gas 11% Significant future growth potential Deep Gas 16% Large undeveloped opportunity in both dry and liquids-rich natural gas 33,000 acres in the Montney 67,000 acres in the Stacked Mannville 70,000 acres in the Duvernay Other Oil & Gas 29% Other oil 6%, other gas 23% 1

31 MMBOE Evaluated Oil Resources in our Portfolio Tight Oil: Crude Oil 63 undeveloped drilling locations in 2P reserve report MMBOE MMBOE Contingent resource assessment at Fort Berthold: 90% land utilization for Bakken, 35% land utilization for Three Forks 78 incremental drilling locations 2 wells/dsu for Bakken and 2 wells/dsu for Three Forks Waterfloods: P Reserves 2011 Contingent Resources* Waterfloods Tight Oil Other Conventional OOIP of ~1.6 billion barrels 2P reserves booked to average 26% recovery across waterflood properties Contingent Resource: IOR and EOR opportunities totaling 56 MMbbls with incremental recovery of 5 15% * Best estimate of contingent resources assessed at December 31,

32 Further Oil Upside Potential in our Portfolio Prospect Comments Upside Potential North Dakota Increased density to 4 Bakken wells/dsu 100 drilling locations North Dakota Increased Three Forks land utilization to 90% ~60 drilling locations Emerging Light Oil Plays in Canada 40+ net sections of land OOIP/section: MMbbls Density: 4 wells/section ~160 drilling locations Waterfloods Properties not included in Contingent Resource estimate ~100 drilling locations Waterfloods EOR Potential Unassessed waterflood properties Pembina, Gleneath, Joarcam, Brooks OOIP of ~700 MMbbls 5 15% recovery 3

33 Bcf Evaluated Natural Gas Resources in our Portfolio 823 Bcf 2P natural gas reserves 2,500 Natural Gas PDP: 58% Proved: 69% 2, P net natural gas drilling locations 1, Marcellus, 134 other gas 1,000 Proved: 67 Probable: P Reserves 2011 Contingent Resources* 2.3 Tcf of contingent resources attributable to the Marcellus 1.4 Tcf operated Marcellus Other 0.9 Tcf non-operated 430 net future drilling locations 261 non-operated 169 operated * Best estimate of contingent resources assessed at December 31,

34 Further Natural Gas Upside Opportunity Play Upper Montney Duvernay Shale Stacked Mannville Acreage/ Sections 33, sections 70, sections 67, sections OGIP/ Section (Bcf) Est. Recovery Liquids Content (bbls/mmcf) Density/ Section (wells) Well Costs ($MM) EUR (Bcfe/well) % $ % $ % $ Total 265 sections 5

35 Joint Venture/Monetization Potential We have more opportunity in our portfolio than we can reasonably develop Over $10 billion of potential capital could be required to develop these opportunities We have retained advisors and are seeking joint venture partners or partial monetization Operated Marcellus 65,000 net acres Montney 33,000 net acres Duvernay 70,000 net acres 6

36 Our Operational Focus in 2012 Execution at Fort Berthold Reduce cycle times on new wells Reduce downtime Test downspacing Continue to advance on our waterflood projects Advance EOR pilots at Giltedge & Med Hat Drilling/injector conversions to enhance efficiencies Delineate new resource plays in Canada Montney, Duvernay, emerging oil plays Spend to maintain Marcellus land position Continued focus on cost management Capital efficiencies Operating costs Expected exit capital efficiencies of $30,000 - $35,000/BOE/day 7

37 2012 Capital Spending Details 2012 Capital Spending Breakdown 2012E ($ millions) Development Drilling & Completions $600 Plant/Facilities 70 Maintenance 30 Exploration* & Seismic 100 Total $800 $300 million targeted at Fort Berthold and $150 million to modestly grow waterflood production $190 million in Marcellus ($150 million non-operated/$40 million operated) focused on lease retention drilling and limited delineation of operated leases No spending on Canadian shallow gas assets $80 million to delineate Montney, Duvernay, emerging oil plays and operated Marcellus acreage positions $65 million of development spending in Deep Basin primarily Stacked Mannville * Includes delineation 8

38 Capital Spending Flexibility Unlikely to reduce capital spending meaningfully in 2012 Most spending is oil focused Preserving leases in Marcellus Equity issue provided support for our plans 2013 early view If depressed gas prices prevailed and no progress made on JV/asset sales: Oil focused Limited operated Marcellus spending and lower non-op spending Reduced Stacked Mannville spending Reduced delineation spending 9

39 BOE/day 2012 Production Build by Play Type 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 AA Growth 43% 3% 168% -11% Total oil production is expected to increase by 22% this year 2012 gas production essentially flat with Marcellus growth offsetting conventional decline Waterflood growth of 3% helps mitigate higher declines of early stage growth assets Quarterly production grows from over 77,000 BOE/day in Q1 to 88,000 BOE/day at exit 0 Q1/11 Q2/11 Q3/11 Q4/11 Q1/12 Q2/12 Q3/12 Q4/12 Other Oil and Gas Marcellus Waterfloods Tight Oil 10

40 2012 Operating Outlook Capital Allocation Average Production Net Operating Income 11% 1% 16% 8% 2% 6% 2% 24% 11% 23% 1% 19% 44% 6% 21% 23% 38% 44% Deep Gas Other Conventional Oil Crude Oil Waterfloods Other Conventional Gas Marcellus Shale Bakken Oil Oil and liquids rich gas plays attract over 70% of our capital in 2012 Oil and liquids production in our portfolio is increasing to 50% of the corporate total by year-end 90% of our expected net operating income is derived from oilfocused resource plays * 2012 estimates 11

41 The Game Plan Canadian Opportunity Ray Daniels, Senior Vice-President, Canadian Operations Enerplus Analyst Day April 2012

42 Steady Growth Potential in Our Canadian Portfolio Existing oil waterflood prospects 14 properties at various stages of maturity Large OOIP: over 1.6 billion barrels of which 21% has been recovered Low decline of ~12% Free cash flow generation 50% reinvestment modestly grows production Offset decline from secondary and tertiary recovery Growth potential by applying IOR/EOR Estimate incremental recoveries for EOR ranging from 5 to 15% of OOIP Ongoing application of reservoir modeling and investment to improve secondary recovery Polymer injection pilot projects could open up new reserves in various other fields Work being done on ASP (Alkaline Surfactant Polymer); CO 2 and MEOR (Microbial EOR) that could add contingent resource 1

43 Steady Growth Potential in Canadian Portfolio (cont d) Meaningful emerging light oil opportunities: 40+ net sections, ~100% WI OOIP: MMbbls/section Estimated recovery: 8 10% EUR: 250 Mbbls/well, 4 wells per section Organic growth from recently acquired natural gas and liquids rich resource plays that have good tenure Over 260 net sections of prospective land with over ~1,200 possible future locations Over $10 billion of capital Portfolio management to support capital requirements and improve operating metrics 2

44 Canadian Waterflood Assets Key Facts OOIP P+P Reserves (YE 2011) Recovered to date 21% ~1.6 billion barrels (net) 90 million barrels net (26% recovery) Best Est. Contingent Resources Average Oil Quality 2012E Annual Production 56.3 million barrels 30 API 17,000 BOE/day 21% of total IOR Improved Oil Recovery (Secondary recovery) EOR Enhanced Oil Recovery (Tertiary recovery) Line of sight to grow production by ~5% per year through focused IOR/EOR 2012 program in support of strategy Spend $150 million on ~40 horizontal high working interest operated oil wells and upgrading facilities Implement EOR projects 3

45 Defining the IOR/EOR Opportunity Asset OOIP (net) (MMBbl) Total Recovered (MMBbl) 2011 YE 2P Reserves (MMBOE) Contingent Resource (MMBbl) IOR EOR Total Total Recoverable 2011 Net Operating Income Medicine Hat, AB % $42.50/BOE Giltedge, AB % $44.00/BOE Freda/Skinner Lake/Neptune, SK % ~$60.00/BOE Cadogan, AB % $54.00/BOE Virden/Daly, MB % ~$63.00/BOE Sub-Total* % Further Upside Potential Field OOIP (MMBbl) Total 2P Reserves (MMBOE) Recovery Factory for Oil Reserves Total Recovered EOR/ IOR Pembina % 28% Both Gleneath % 19% Both Joarcam % 40% Both EOR potential also at Freda/Skinner Lake/Neptune; Virden/Daly ~340 net locations to unlock potential value of our assets Brooks % 30% IOR * There are other waterflood properties that contribute to reserves and production within this resource play that are not included above 4

46 Why Polymer Flooding? Polymer proven technology used today Rigorously screened our entire waterflood portfolio to evaluate IOR/EOR potential Potential IOR and EOR solutions tested for economic viability Polymer flood minimum requirements: Minimum rate of return >25% Polymer won t work in high temperature environment need reservoir depth less than 2,700 metres and temperature less than 90 degrees Celsius Well established and effective IOR infrastructure - leverage existing waterflood to lower EOR capital Core work to validate polymer effectiveness Polymer doesn t work well in high solution gas environment - GOR close to Rsi is better Pilot scheme to confirm in-situ EOR effectiveness 5

47 Giltedge Project Update Key Facts Polymer Project Area OOIP 126 MMBbl Recovery Factor to Date ~13% Cumulative Production 17.8 MMBbl P+P Reserves (Dec 31, 2011) Best Est. Contingent Resource Oil Quality 2012E Avg. Production 11.0 MMBOE (booked to 22%) IOR 4.0 MMBOE EOR 11.8 MMBOE API ~2,000 BOE/day oil, 97% water cut 59% of cash flow reinvested over last 2 years has grown production 29% and maintained reserves Polymer project has estimated incremental recovery of 10% (11.8 MMBOE) Polymer injection wells 100% Working Interest 6

48 How does Polymer Flooding EOR (Enhanced Oil Recovery) Work? Traditional heavy oil waterflood Polymer flood demonstrating better sweep Polymer increases the sweep efficiency (i.e. how effectively the injected fluid moves the oil) and recovers more of the oil Source - Malcolm Pitts, Surtek February D test simulating water injection through artificial reservoir rock in top 3 slides and polymer injection in bottom 3 slides 7

49 Giltedge Polymer Project Update Production: Incremental: 400 bbls/day Reserves: Incremental: 800 Mbbls EOR Project Economics: NPV10: $20 million IRR: ~30% EOR Project Costs: Facilities: $10 million Polymer: $10 million (evenly over 4 years) Incremental Op. Cost: $0.70/BOE Netback: $44/BOE Initiated both IOR and EOR polymer injection in 2011 with polymer breakthrough in July 2011 Production increased 28% from early 2011 to 2,200 BOE/day at exit ~ 200 BOE/day attributed to polymer Booked 800,000 bbls of new reserves due to polymer pilot and 500,000 bbls due to ongoing pool wide optimization Expanded the polymer project and added polymer to three injection wells in January 2012 Anticipate average oil cuts to increase from 2% to approximately 10% with a 2x to 3x increase in production in next months Full field development will be staged, with stage 2 decision in late 2012/early

50 Medicine Hat Glauc C Polymer Potential Key Facts Second Project Area OOIP 217 MMBbl Recovery Factor to Date ~8% Cumulative Production 17.7 MMBbl Polymer Project Area P+P Reserves (Dec 31, 2011) Best Estimate Contingent Resource Oil Quality 2012E Avg. Production 16.7 MMBOE (booked to 16%) IOR 5.5 MMBOE EOR 21.7 MMBOE 11 to 18 API 2,750 BOE/day, 91% water cut 54% reinvestment over past 3 years has grown production by over 30% and maintained reserves Currently 115 producing and 60 injection wells Polymer project has estimated incremental recovery of 10% (21.7 MMBOE) 72% WI across ~14 sections 9

51 MHGC Polymer Project Update Production: Reserves Incremental: 600 bbls/day Incremental: 1 MMBOE EOR Project Economics: NPV10: $17 million IRR: ~45% EOR Project Costs: Facilities: $5.8 million net Polymer: $7.2 million (evenly over 4 years) Incremental Op. Cost: $0.30/BOE 21.7 million barrels of contingent resource related to EOR Polymer project in final stages of execution and moving into commissioning Initial polymer injection expected by end of Q2/12 Initial polymer breakthrough expected in 9 to 12 months from initial injection Will monitor response through 2013 and into 2014 Decision on next stage of EOR development will be made mid-2014 Netback: $42.50/BOE 10

52 Defining the Gas Opportunity (Deep Gas) Stacked Mannville Potential 67,000 net acres of land (42,000 undeveloped) Duvernay Potential 70,000 net acres of undeveloped land Montney Potential 33,000 net acres of undeveloped land Approximately 170,000 net acres of high working interest land throughout the region Includes 100% working interest in approximately 145,000 undeveloped acres Multiple contiguous acreage blocks Potential of liquids rich zones 2012 capital focused on delineating the resource given price environment Duvernay 2 vertical strat wells Montney - 1 vertical strat and 1 hz SM Wilrich 2 hz producers Large, long tenure, high working interest land holdings 11

53 Stacked Mannville Key Facts Key properties Net Acreage (acres) Pine Creek to Hanlan ~67,000 total (42,000 undeveloped) Future HZ Drilling Locations Expected EUR/Well Bcfe Acquiring and utilizing 3D seismic Drilled 5 Hz delineation wells to date, 3 others licensed and ready to execute Liquids ratios of 7 30 bbls/mmcf Additional de-risking ongoing by competitors and partners Contiguous land blocks in highly prospective regions Enerplus working interest lands 12

54 Wilrich Type Curve Economics AECO ($/Mcf) IRR % 4.0 Bcf Well 6.0 Bcf Well Payout (Years) NPV 10% ($MM) IRR % Payout (Years) NPV 10% ($MM) $ $ $ Capital* $7.1 million $7.1 million 30 Day IP 3,800 Mcf/day 6,000 Mcf/day Liquids 7 bbls/mmcf 7 bbls/mmcf BESC $2.81/Mcf $1.61/Mcf Type curves are based on offset data and are supported by our well results Positive drilling results to date: Horizontal drill - 13 MMcf/day (facility constrained) peak rate production at 14 Mpa after 165 hours with 15,549 bbls of water recovered Produced at 10 MMcf/day for first 30 days Second horizontal drill - 31 MMcf/day (facility constrained) peak rate production at 19 Mpa after 90 hours with 6,900 bbls of water recovered * Capital assumes pad drilling 13

55 Montney Cameron/Julienne Creek Key Facts Progress/Petronas North Montney JV (Lily) North Montney Regional Pool Key Properties Net Acreage Estimated OGIP Future Hz Drilling Locations Expected EUR/Well Cameron/Julienne Creek ~33,000 acres (+50 sections) 150 Bcf/section Bcfe Montney Vert. Test Well Progress Town Enerplus Julienne Creek Lands 3D seismic outline T North Sales Line Painted Pony Blair 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 54 14

56 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) $ $ $ (1.2) Capital $6.2 million $6.2 million $6.2 million 30 Day IP 4,000 Mcf/day 5,000 Mcf/day 6,000 Mcf/day Liquids bbls/mmcf bbls/mmcf bbls/mmcf BESC $2.78/Mcf $1.99/Mcf $1.47/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 15

57 Why the Duvernay Shale at Willesden Green? Duvernay has analogous rock characteristics to the Eagleford Prolific over-pressured Devonian source rock Within the gas condensate window, based on: Offsetting well control and reported competitor activity Equivalent thermal maturity and depth to proven liquid-rich Kaybob area Existing and newly announced mid-stream gas infrastructure, including deep cut gas plants, provides numerous options for product marketing 4 well/section development provides us with over 400 future Hz drilling locations 110 sections in the gas condensate window with net OGIP of +7 Tcf Favorable royalty of 5% for first 5 years of production 56 16

58 Duvernay Shale Willesden Green Sinopec Daylight Key Facts Key Properties Net Acreage Willesden Green, AB ~70,000 acres (110 sections) Sirius COP Antelope Est. OGIP Est. Density Expected EUR/Well ~65 Bcf/section 4 wells/section 3.5 Bcf Bellatrix COP ECA Early stage liquids rich natural gas play in central Alberta ECA Bonavista ECA Over-pressured at ~56MPa Targeted type well: ECA Hz well cost of ~$12 million 30 day IP of ~5 MMcf/day Licenced Wells Drilled/Drilling Wells TLM Enerplus Duvernay Land sales (since Dec/2010) Liquids bbls/mmcf Focus on early stage evaluation in wells planned for Q3/Q4 Duvernay Penetrations 17

59 Summarizing Canadian Opportunities Portfolio of oil assets that provide a stable foundation for cash flow generation and future production growth through IOR and EOR Portfolio of large scale, large scope growth opportunities in high quality deep gas and liquids rich gas plays Portfolio of growth opportunities in early stage oil resource plays Strong technical team in place focusing on maximizing the value of Canadian Operations through focused exploration and development and operational excellence 18

60 The Game Plan Marcellus Investing for the Future Ian Dundas, Executive Vice-President and Chief Operating Officer Enerplus Analyst Day April 2012

61 Significant Low Cost Resource Capture $ Millions Initial Investment $ 440 Additional Acquisitions 160 Capex (net of income) 310 Total Investment $ 910 Sold Portion of Interests* (580) Net Invested $ 330 2P NPV10% at December 31/11* $ 200 Contingent Resource 2.3 Tcf Acquisition Cost per Mcf of CR <$0.10 Significant resource capture through acquisitions and delineation drilling Partial sale resulted in more manageable, concentrated position Retained 110,000 net acres including concentrated nonoperated acreage in NE PA and operated positions in Central PA, WV and MD Significant long-term reserves and production growth potential * Before tax 1

62 2012 Non-Operated Plans Focused on Lease Retention $150 million capital budget for 2012 Rig count has dropped while maintaining the minimum needed for lease obligations 19 net new drills planned in 2012, 18 on-streams ~50% of 2012 drilling planned in areas with water and pipeline infrastructure already in place 90% of 2012 capital program targeted in locations with anticipated EURs of 7-9 Bcf/well ~50% in 9 Bcf/well areas Planned 2012 Rig Activity by Non-Op Partners on Enerplus Acreage EXCO Resources Chief O&G & CHK 20 Partners are managing activity in current market conditions Sep-11 Jan-12 Current 2

63 2012 Operated Plans Focused on Delineation Preston County, WV (43,000 net acres) 3 delineation wells drilled to date No further drilling planned for 2012 Garrett County, MD (17,000 net acres) No drilling activity Government review process re: fracing underway Clinton County, PA (7,000 net acres) 2 wells drilled to date 2011 drill flowed 8.3 MMcf/day (24 hour peak rate at 2,900 psi flow tubing pressure) Better than expected 3.5 MMcf/day rate Drilled 1 well in Q1 2012, completing build out of water infrastructure 3

64 Net Daily Production Rate (Mcf/day) 2P Reserves (MMBoe) Marcellus Production Growth 60,000 50, net wells E exit production: >70 MMcf/day (+180% vs 2011) 40,000 30, Production has increased from 1 MMcf/day to 30 MMcf/day currently, despite sale of 5.4 MMcf/day 20, net wells Reserves have increased by 600% to over 153 Bcf at yearend ,000 3 net wells E 0 Daily Production Rate Reserves Growth 4

65 Cumulative Production (MMcfe) Well Performance Continues to Exceed Expectations N.E. PA Well Performance Top 5 Wells Average Actual Production Average EURs have increased from Bcf/well to 6.6 Bcf/ well Bcfe Type Curve 3.5 Bcfe Type Curve Increased land utilization from 55% to 65% High EUR estimate has increased from 5 Bcf/well in 2009 to an average of 11 Bcf/well today in Susquehanna County Days Producing 5

66 Marcellus Well Economics Non-Operated Virtually all of non-operated spend in 2012 is in areas with 7 9 Bcf type wells NYMEX $/MMBtu IRR Payout * (Years) 7.0 Bcf Well NPV 10% ($MM) Netback ($/Mcf) Recycle PIR 10% $ % 4.0 $2.2 $ x 0.3 $ % NA ($0.5) $ x - $2.50 0% NA ($3.1) $ x - NYMEX $/MMBtu IRR Payout * (Years) 9.0 Bcf Well NPV 10% ($MM) Netback ($/Mcf) Recycle PIR 10% $ % 2.6 $5.3 $ x 0.8 $ % 4.2 $1.8 $ x 0.3 $2.50 3% NA ($1.7) $ x - * Undiscounted payout shown. All economics assume per well cost of $7 million 6

67 Marcellus Lease Tenure Non-Operated (~47,000 net acres in PA) Operated primarily by Chief, Exco and Chesapeake Anticipate 30% - 35% of leasehold to be held by production by end of 2012 Approximately 22,000 net acres expire in 2013 Expect majority to be either extended under pre-negotiated options or to be held by production via drilling activity results in ~70% of prospective acreage held by end of 2013 Operated (~68,000 net acres) Pennsylvania (~7,000 net acres) Majority of leases expire in 2015 West Virginia/Maryland (~61,000 net acres) Expirations (acres): 2012: 28,000 acres - 95% of leasehold can be extended for $1.6MM 2013: 29,000 acres - 90% of leasehold can be extended for $15.8MM 2014+: 4,000 acres 7

68 The Game Plan Fort Berthold, ND Ian Dundas, Executive Vice-President and Chief Operating Officer Enerplus Analyst Day April 2012

69 Fort Berthold Leads the Charge in Oil Growth Current Operated and Non-Operated Locations Key Facts Net Acreage (acres) ~74,000 (115 sections) 2011 P+P Reserves 55.4 MMBOE 2011 Best Estimate Contingent Resources 2011 Q4 Production 2011 Exit Production 2012E Exit Production 49 MMBOE 6,800 BOE/day 9,000 BOE/day ~15,600 BOE/day Concentrated, top tier land position in North Dakota Average 90% working interest 32 horizontal operated wells drilled to date Expected netback of $50 - $55/BOE in

70 Locations Drilling Inventory at Fort Berthold Contingent Resource YE 2011 Booked Net P+P-UD Bakken Contingent Net Locations Three Forks Contingent Net Locations Total Booked Reserves & Contingent Resource 2

71 2011 Operational Highlights Production growth: 6,800 BOE/day in Q (+79% over Q4 2010) Reserve growth: 150% increase in 2011 Advanced field delineation: Drilled 25 wells (operated, 18 shorts, 7 longs) Completed 5 Three Forks wells Completed 2 high density tests (2 Bakken/2 Three Forks wells) (3 Bakken wells) Completed micro seismic program Infrastructure build-out Salt Water Disposal well (SWD) 3 rd party oil and gas gathering system 30% of wells tied-in at year-end 3

72 2012 Key Deliverables Drilling ~30 wells 90% long horizontals Production growth 70% increase exit 2011 to exit 2012 Implement cost mitigation measures Operations optimization reduce downtime, shorten cycle-times Advance reservoir model understanding Monitor high density wells 4

73 Cumulative Production (bbls) Daily Production (bbl/day) Cumulative Production (bbls) Daily Production (bbl/day) Bakken Well Results Continue to Outperform Bakken Long Well Performance Bakken Short Well Performance wells 5 wells 4 wells 3 wells 2 wells 1 well 1,400 1,200 1, PLACEHOLDER ONLY: NEED THE daily type curve 5 wells 9 wells 11 wells 3 wells 1 well 2 wells Months wells Months 0 Cumulative Type Curve Daily Production Type Curve Actual Cumulative Average Actual Daily Average Cumulative Type Curve Daily Production Type Curve Actual Cumulative Average Actual Daily Average 5

74 Fort Berthold Bakken Economics Bakken Long Laterals 9,500 ft frac stages, $11 MM/well Type Curve 30 Day IP 1,240 bbls/day EUR: Oil Gas NGLs 940 MBOE 800 Mbbls 470 MMcf 75 Mbbls IRR 90% Net Present Value (10%)* Payout Period $17 million 1.2 years Recycle Ratio 4.0x * Economics are before tax in US dollars based on March 26, 2012 forward prices. Royalties average 19.5%, plus state production and extraction tax of 8.5% 6

75 Cumulative Production (bbls) Daily Production (bbl/day) Cumulative Production (bbls) Daily Production (bbl/day) Promising Early Three Forks Results Long Three Forks Well Performance Short Three Forks Well Performance Months Months 0 Well 1 Well 2 Cumulative Type Curve Daily Production Type Curve Cumulative Type Curve Well 1 Well 2 Well 3 Well 4 Well 5 Daily Production Type Curve 7

76 Fort Berthold Three Forks Economics Three Forks Long Laterals 9,500 ft frac stages, $11 MM/well Type Curve 30 Day IP 870 bbls/day EUR: Oil Gas NGLs 650 MBOE 550 Mbbls 300 MMcf 50 Mbbls IRR 40% Net Present Value (10%)* Payout Period $8.3 million 2.2 years Recycle Ratio 2.7x * Economics are before tax in US dollars based on March 26, 2012 forward prices. Royalties average 19.5%, plus state production and extraction tax of 8.5% 8

77 Three Forks Three Forks Middle Bakken Middle Bakken Well Spacing (1280 acres per drilling spacing unit) 2P (EUR) 2P + CR (EUR) Potential Upside ???? Lower Bakken Lower Bakken Lower Bakken ??? Estimated Recovery: 1.6 million bbls/dsu 13-18% recovery factor Estimated Recovery: 2.7 million bbls/dsu 12-16% recovery factor Estimated Recovery: 3-4 million bbls/dsu up to 18% recovery factor Early Learnings: Bakken and Three Forks communicate during completion Bakken and Three Forks appear capable of communicating during production Bakken wells appear to outperform Three Forks contribution? 2 wells/dsu likely underdeveloped Bakken OOIP: 9-12 million bbls/dsu Three Forks OOIP: 8-10 million bbls/dsu 9

78 Cost Mitigation Efforts & Field Optimization Improved drilling cycle times Best rig now averaging 30 days for long drill well versus 37 day average Completion design Testing coated resin Optimize stages, water, proppant Water management Full year of salt water disposal well Reduction in completion costs Add second SWD well in Q2 Evaluating piping system for SWD Continue infrastructure build out for well tie-ins 30% of wells tied-in now, 75% expected by year-end Production optimization Increase in service rigs to improve uptime target 50% reduction in downtime 10

79 North Dakota Takeaway Capacity Rail and pipeline commitments in place for 8,500 bbls/day in 2012 and 14,000 bbls/day in ,000 to 3,000 bbls/day directly exposed to LLS pricing through Feb

80 BOE/day Long-Term Cash Flow Growth Potential Fort Berthold 30,000 25,000 20,000 15,000 10,000 5, $500 $400 $300 $200 $100 $0 -$100 $ Millions Growth potential of ~25,000 BOE/day by 2015 Over 130 future drilling locations currently identified Free cash flow projected in late 2012/early 2013 Net operating income approaching $500 million by 2015 Recycle ratios of x - -$200 Capital Net Op Income Production Free Cash Flow (NOI - Capex) 12

81 The Game Plan Summary Enerplus 2012 Analyst Day

82 Outlook Good mix of early stage, high growth, and mature oil and gas properties Abundance of growth opportunities in our portfolio today not reliant on acquisitions Strong 2011 results with respect to organic reserve replacement through organic growth and F&D costs Oil weighting is increasing: 75% of 2011 reserve additions were from oil and liquids 57% of 2P reserves weighted to oil and liquids 50% production weighted to oil and liquids by end of % of capital spending directed to oil & liquids in 2012 Healthy balance sheet and plan to manage debt levels in the context of weak natural gas prices Objective is to deliver competitive total return comprised of sustainable growth and income

83 The Game Plan Questions and Answers Enerplus 2012 Analyst Day

84 The Game Plan Supplemental Information Enerplus 2012 Analyst Day

85 Competitive Finding & Development Costs in 2011 Company Mid Cap 2P Total Reserves Including FDC 2P Reserve Additions 2P F&D 2P FD&A MMBOE % Liquids MMBOE % Liquids ($/BOE) ($/BOE) Baytex % % Crescent Point % % Enerplus % 48 75% Penn West % % PetroBakken % Oil Weighted Mid Cap Average % % ARC % % Bonavista % % NAL % Pengrowth % % Progress % Vermilion % of reserve additions from oil and liquids F&D costs attractive despite $150 million of capital that did not add reserves in 2011 FD&A costs reflect the value captured in the sale of the Marcellus interests for $580 million Mid Cap Average % % * Based on 2P company interest reserves at December 31, 2011, including FDC. Recycle ratios calculated using FD&A and exclude the impact of hedging.

86 North Dakota Differentials Two supply/demand components impacting differentials: Field Level: Shortage of takeaway capacity is no longer the case in the region, however field gathering is still reliant on trucking Incremental rail brought online recently means takeaway capacity exceeds production Shippers with rail contracts are competing for oil due to fixed costs of holding rail capacity (demurrage, rail car rentals, etc.) Results in improved field netbacks, especially if rail contracts provide exposure to Gulf Coast pricing Macro Level: Light/heavy differentials remain under continued pressure due to increasing oil supply and limited takeaway capacity to the Gulf Coast Seaway expansion will provide some relief in 2012, with further regional takeaway expected to improve congestion at Cushing in 2013

87 Disclaimers Assumptions All economics contained in these presentations have been calculated using forward prices and costs as of March 26, All amounts in these presentations are stated in Canadian dollars unless otherwise specified. Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent These presentations also contain 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. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively. 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 these presentations (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, 2011, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI , is in our Annual Information Form for the year ended December 31, 2011 ("our AIF") which is available on our website at and under our SEDAR profile at Additionally, the AIF forms part of our Form 40-F that has been filed with the U.S. Securities and Exchange Commission and will available on EDGAR at Readers are also urged to review the 2011 Management s Discussion & Analysis and financial statements filed on SEDAR and EDGAR for more complete disclosure on our operations. Contingent Resource Estimates These presentations contain 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 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." 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.

88 Disclaimers For additional information regarding the primary contingencies which currently prevent the classification of our disclosed contingent resources associated with our Marcellus shale gas assets, our North Dakota Bakken properties and our crude oil waterflood properties as reserves and the positive and negative factors relevant to the contingent resource estimates, see our Annual Information Form for the year ended December 31, 2011 (and corresponding Form 40-F) dated March 9, 2012, 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 will not 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 will not reflect total finding, development and acquisition costs related to its reserves additions for that year. Non-GAAP Measures In this presentation, we use the terms funds flow, "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "F&D costs" and FD&A costs 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 Canadian generally accepted accounting principles ( GAAP ) which were revised effective January 1, 2011 to converge with 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. Enerplus believes that, in addition to net earnings and other measures prescribed by GAAP, the terms funds flow, "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 GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. NOTICE TO U.S. READERS The oil and natural gas reserves information contained in these presentations 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.

89 Disclaimers 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 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. 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, these presentations contains forward-looking information pertaining to the following: Enerplus' strategy to deliver both income and growth to investors and Enerplus' related asset portfolio; future returns to shareholders from both dividends and from growth in per share production and reserves; future capital and development expenditures and the allocation thereof among our resource plays and assets; future development and drilling locations and plans; the performance of and future results from Enerplus' assets and operations, including anticipated production levels 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; securing necessary infrastructure and third party services; the amount of future asset retirement obligations; future cash flows and debt-to-cash flow levels; potential asset sales; returns on Enerplus' capital program; Enerplus' tax position; and future costs, expenses and royalty rates. The forward-looking information contained in this presentation reflects 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 and cash flow 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' AIF and Form 40-F described above). 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.

90 Investor Relations Contacts Jo-Anne M. Caza Vice President, Corporate & Investor Relations Garth Doll Manager, Investor Relations The Dome Tower Suite 3000, 333 7th Ave SW Calgary, AB Canada T2P 2Z1