TD Securities London Energy Conference January 2013

Transcription

1 The Game Plan TD Securities London Energy Conference January 2013

2 Why Enerplus? Solid financial strength and improving sustainability Top tier assets Compelling dividend Attractive valuation 1

3 Adjusted Payout Ratio Financial Strength and Improving Sustainability 230% 210% 190% 212% 190% Significant value creation from A&D activity has: Supported capital investment and dividend Preserved balance sheet 170% 150% 130% 110% 127% 140% 144% 156% 130% 128% Expect to manage cash flow shortfall via: Cost reductions Non-core asset sales 90% Debt to cash flow reasonable at under 2.0x 70% 50% E 2013E APO without Net A&D or DRIP Proceeds APO, including Net A&D and DRIP Proceeds 2

4 Top Tier Assets Balanced portfolio of oil and gas in both Canada and the US 45% crude oil, 5% nat gas liquids 50% natural gas 60%Canada / 40% US Resource play focus with significant growth potential Crude Oil - Bakken US Natural Gas - Marcellus Canadian liquids rich natural gas: Stacked Mannville Duvernay Montney IOR/EOR potential in mature assets Low decline, cash generating assets High working interest ~24% average corporate decline rate 3

5 BOE/day Top Tier Assets Delivering Organic Growth 90,000 80,000 75,332 81,573 82,000 85,000 88,000 82,000 85,000 84,000 88,000 70,000 60,000 50,000 40,000 30,000 20,000 10, AA 2012 YTD 2012E AA 2012E Exit 2013 AA 2013 Exit Oil & Liquids Natural Gas 4

6 MMBOE $/BOE Competitive Reserve Addition Costs $30 $25 $26.26 Oil reserves increased by 14%: $20 $15 $17.22 $ % of reserve additions from oil and liquids $10 $5 $ $ F&D* 2011 FD&A* Excl. FDC Incl. FDC 47% 43% 53% 57% P Reserves* Crude Oil and Liquids P Reserves* Natural Gas Oil recycle ratio of 1.9x F&D costs attractive despite $150 million of capital that did not add reserves in 2011 Total 2P reserves increased by 5% NPV of reserves increased by 10% in 2011 due to increased weighting of oil in portfolio NPV of Fort Berthold oil property up 160% due to success of drilling program * Based on 2P company interest reserves at December 31,

7 Attractive Valuation Enerplus Peer Average (Range) 2013E Price/DACF 4.8x 2013E EV/EBITDA 5.0x 2013E EV per Daily BOE $45, E Debt to Cash Flow 1.7x After-Tax Price/NAV (10% discount) 76% Yield 8.4% 7.8x (4.8x 10.6x) 8.1x (4.8x 10.6x) $87,832 ($39,723 $150,788) 2.0x (0.8x 3.8x) 77% (53% - 97%) 6.8% (3.1% %) Source: BMO Capital Markets research dated January 2, Peer group includes ARC, Baytex, Bonavista, Crescent Point, Enerplus, Pengrowth, PennWest, PetroBakken, Peyto, Trilogy and Vermilion. BMO Pricing Assumptions: WTI 2013 US$87.00/bbl; AECO 2013 CDN$3.10/Mcf; 2013 US$/CDN$1.00 6

8 2013 Outlook Funds flow growth of 11% Debt-adjusted funds flow grows 6% per share Reduced capital spending by 20% Reduced spending on Marcellus gas 85% of spend on oil and liquids rich natural gas plays Focused on improving capital efficiencies Average production expected to increase by 2% over 2012 Crude oil production expected to increase by 2.5% and to account for 50% of total production Adjusted payout ratio improves to ~130% Balance sheet remains strong Expected debt to funds flow ratio of 1.9x at YE

9 Why Enerplus? Financial strength and improving sustainability Improving cost structures and capital efficiencies Delivering attractive reserve, production growth and funds flow growth Top Tier assets Low decline asset base with significant inventory of oil and gas opportunities in portfolio to deliver future growth in reserves and production Compelling dividend Current yield of ~8% Attractive valuation relative to asset value and peers Upside exposure to improving natural gas prices with growing NYMEXbased natural gas production 8

10 2013 Outlook

11 Guidance Overview Operations and Expenses* 2012E 2013E Change Capital Expenditures ($millions) $850 $685-20% Annual Average Production (BOE/day) 82,000 82,000 85,000 +2% Exit Production (BOE/day) 85,000 88,000 84,000 88,000 - Oil & Liquids Weighting 49% 50% +1% Operating Expenses ($/BOE) $10.70 $ G&A (including non-cash amounts) ($/BOE) $3.30 $ % Royalties 20.5% 21% - * Based upon forward commodity prices and forecast costs at time of guidance release (November 26, 2012) including the impact of hedging. Does not include any acquisition or divestment activities not previously announced. Forecast YE2012 debt is approximately $1.1 billion. ** 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. 10

12 % of net after royalty production Cash Flow Protection 100% 80% 2013 Crude Oil & Natural Gas Hedge Positions* Crude oil hedges on 57% of 2013 net production at a fixed price averaging US$100.84/bbl Natural gas hedges on 2013 net production: 60% 12% swapped at $3.63/Mcf at AECO for the full year 40% 20% 0% 57% swaps Crude Oil 11% puts 11% puts 20% swaps 12% swaps Natural Gas First 6 mos Natural Gas Last 6 mos 8% swapped at US$3.45/Mcf at Nymex from Jan-June 11% of gas production with put protection averaging $3.17/Mcf at AECO Targeting additional hedging in 2014 * Based on weighted average price (before premiums), average annual production of 82,000 85,000 BOE/day for 2013, less royalties of 21%. 11

13 2013 Capital Budget Pricing and Sensitivity 2013 Forward Prices as of Nov 26, 2012 Oil - WTI (US$/bbl) $90.39 Oil Edmonton Par ($/bbl) $85.73 Gas NYMEX (US$/Mcf) $3.96 Gas AECO ($/Mcf) $ Sensitivities Est. effect on 2013 Funds Flow/Share Change of $5.00/bbl WTI crude oil $0.14 Change of $0.50/Mcf AECO natural gas $0.18 Change of 1,000 BOE/day production $0.05 Change of $0.01 in the US$/CDN$ exchange rate $

14 Production Composition and Differentials 2013E Production 2013E Crude Oil Composition US Gas 16% US Oil 24% Canada Heavy 25% Canada Gas 34% NGLs 4% Canada Oil 22% Estimated 2013 Differentials US Light US$13.25 Canada Light US$13.00 Canada Medium US$16.00 Canada Heavy US$21.00 Canada Medium 12% Canada Light 11% US Light 52% 13

15 Crude Oil Differentials in North Dakota Rail (~50% of takeaway capacity in 2013) has debottlenecked North Dakota Used rail as an option to ensure takeaway and help reduce impact of wider differentials: ~30% of our US Bakken production transported on rail in 2012, ~70% through pipelines ~15% is exposed to LLS pricing US Bakken Differentials 14

16 Ample Takeaway Capacity in North Dakota 15

17 Asset Review: Crude Oil

18 Top Tier Light Oil Play in North Dakota Current Operated and Non-Operated Locations Key Facts OOIP MMbbls/1280 DSU Net Acreage (90% WI) ~70,000 (110 sections) 2011 P+P Reserves 55.4 MMBOE 2011 Contingent Res. Est. 49 MMBOE Future Drilling Locations 2013E Average Production 130+ (2P & CR) 16,000 BOE/day Concentrated, top tier land position in North Dakota Dunn & McKenzie counties Prospective for Bakken and Three Forks throughout entire acreage positions Average ~90% operated working interest 4 6 years drilling inventory at current pace 17

19 BOE/day Delivering Organic Oil Growth at Fort Berthold 2013 production expected to grow over 30% - averaging 16,000 BOE/day 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 - AA 2012E Q Exit 2012E AA 2013E Exit 2013E $340 million of capital spending planned for 2013, 90% on drilling and completions Expect to drill and complete net wells Over 75% of drilling expected to be Bakken and Three Forks long horizontals Focused on improving costs and efficiencies Increased pad drilling expected to result in lower drilling days Rates for completion and other services falling Evaluating optimal well spacing 18

20 Fort Berthold Well Results in Line with Expectations wells 5 6 wells wells wells (400 Mbbls of oil, 55 MBOE of liquids and gas) (800 Mbbls of oil, 105 MBOE of liquids and gas) * Production data as of October 31,

21 North Dakota Economics (long lateral wells) EUR Variables Density Bakken vs Three Forks Range of EURs Mbbls Budgeted Well Costs $12.9 MM Economics* Range of IRRs Projected IRR 17% - 44% 10% Reduction in Well Costs 21% - 55% 10% Change in Crude Oil Price +/- 6% 12% *Using US$90 WTI constant price 20

22 Three Forks Three Forks Middle Bakken Middle Bakken Fort Berthold Well Spacing (1280 acres per drill 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 CR estimate assumes land utilization of: Bakken 90% Three Forks 35% 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

23 Consolidating Ownership at Sleeping Giant Key Facts 2011 P+P Reserves* 32.4 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 * Including acquisition of additional 20% working interest 22

24 Sleeping Giant Purchase vs. Manitoba Asset Sale (Based on internal evaluations and November 23, 2012 pricing) Sleeping Giant Manitoba Purchase Price [$M] * $131,000 $220,000 Working Interest [%] 90% (post transaction) 52% Funds flow multiple* 4.5* 7.0 $/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) * Before deduction of estimated closing adjustments 23

25 Low Decline Canadian Waterflood Assets Average decline rate of ~12% Mature producing properties with low decline rate of ~12% High working interest ownership of over 90% Significant free cash flow generation Over 1.2 billion barrels original oil in place with 22% recovered to date 53.5 million barrels of contingent resource from EOR and IOR potential 2 polymer pilots underway Almost 300 future drilling locations to unlock value * As at Dec. 31, 2011 adjusted for Manitoba waterflood asset sale expected to close December

26 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 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; Sleeping Giant ~300 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 25

27 Waterflood Success Story - Medicine Hat Glauc C 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 (Dec 31, 2011) Oil Quality 2013E Avg. Production 16.7 MMBOE (booked to 16%) IOR 5.5 MMBOE EOR 21.7 MMBOE 11 to 18 API 3,700 BOE/day 45% reinvestment over past 5 years has grown production by over 50% Polymer project has estimated incremental recovery of 10% (21.7 MMBOE) Improved waterflood management has estimated incremental recovery of 3% (5.5 MMBOE) 72% WI across ~14 sections 26

28 Sep 2007 Feb 2008 Jul 2008 Dec 2008 May 2009 Oct 2009 Mar 2010 Aug 2010 Jan 2011 Jun 2011 Nov 2011 Apr 2012 Sep 2012 Average Daily Production (BOE/day) Medicine Hat Glauc C Production History % growth achieved over 5 years with 45% reinvestment Implemented new waterflood development strategy in 2009 Numerous battery upgrades from Moved to 100m inter-well spacing May 2012 polymer pilot success 0 27

29 Asset Review: Natural Gas

30 Marcellus: Reduced Spending on Dry Gas EXCO Resources Chief O&G & CHK 47,000 net non-operated acres with 20% avg. working interest Major non-op partners: EXCO (22% WI) Chief (18% WI) 2013 capital program of $80 million, 50% reduction from 2012 Virtually all spending is non-operated focused on opportunities with robust economics Susquehanna 10% to 25% IRR Bradford 5% to 15% IRR Expect to have retained the majority of core nonoperated acreage by end of 2013 Expect average production of ~65,000 Mcf/day in 2013, up 25% Expecting to exit 2013 at ~75,000 Mcf/day Marcellus gas represents ~25% of expected 2013 corporate natural gas production Current production is over 60,000 Mcf/day Operating netbacks averaging ~$2.00/Mcf * Rates of return estimated using US$3 - US$4/Mcf NYMEX natural gas 29

31 NE Pennsylvania Average Well Performance Wells in top tier acreage significantly outperforming type curve * Production data as of October 31,

32 Rate of Return Marcellus Economics 45% 40% 35% Core areas with 8 to 10 BCF wells deliver positve returns $5/Mcf NYMEX 30% 25% $4/Mcf NYMEX 20% 15% 10% $3/Mcf NYMEX 5% 0% EUR (bcf) Economics based on an $8MM well cost 31

33 An Abundance of Deep Gas Opportunity Montney 33,000 net acres of undeveloped land, 100% WI Approximately 175,000 net acres of high working interest land Stacked Mannville 70,000 net acres of land (42,000 acres undeveloped, 100% WI) Liquids rich potential in Stacked Mannville, Duvernay and Montney Over 900 potential future drilling locations Successful drilling results to date in Stacked Mannville (Wilrich) Joint venture potential in Duvernay & Montney Duvernay 72,000 net acres of undeveloped land, 100% WI 32

34 Deep Gas - Wilrich Key Facts Key properties Net Acreage (acres) Ansell, Minehead, Hanlan ~70,000 acres (110 sections) Future HZ Drilling Locations Expected EUR/Well Bcfe 2013 capital program of ~$40 million focused primarily in Ansell Plan to drill 3 to 5 wells Over 20% IRR Contiguous land blocks in highly prospective regions Enerplus working interest lands 33

35 Cumulative Production (MMcf) Wilrich Type Curve and Performance 5.0 Bcf Well 6.0 Bcf Well Positive Drilling Results AECO ($/Mcf) IRR % Pay out (Yrs) NPV 10% ($MM) IRR % Pay out (Yrs) NPV 10% ($MM) 1,600 1,400 1 Well $ ,200 2 Wells $ ,000 $ 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 Type curves are based on offset data and are supported by our well results Wells Months Producing Average Horizontal Production 6.0 Bcf Type Curve 5.0 bcf Type Curve * Capital assumes pad drilling 34

36 Duvernay: Emerging Top Quality Liquids-Rich Resource Play Key Facts Key Properties Net Acreage Est. OGIP Est. Density Est. EUR/Well Est. Hz Well Cost Est. 30 day IP Est. Liquids Willesden Green, AB ~72,000 acres (113 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 advance project 35

37 Duvernay Shale Willesden Green 36

38 Montney Cameron/Julienne Creek Key Facts Progress/Petronas North Montney JV (Lily) Key Properties Net Acreage Estimated OGIP Future Hz Drilling Locations Cameron/Julienne Creek ~33,000 acres (+50 sections) 150 Bcf/section 500+ North Montney Regional Pool Expected EUR/Well Bcfe Montney Vert. Test Well Enerplus Julienne Creek Lands 3D seismic outline T North Sales Line Progress Town 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 37

39 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 $1.89/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 38

40 Supplemental Information The Game Plan

41 Corporate Profile Ticker Symbol (TSX & NYSE) ERF Enterprise Value (1) $3.7 billion Average Daily Trading Value (through Q3 2012) $49 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 1.9x 1. Market Cap. at January 2, 2013 plus Q net debt of $1.1 billion 40

42 Commitment to Dividend Model Investor Composition Capital markets place higher valuation on dividend paying energy companies 23% 46% US/Intl Institutional US/Intl Retail 13% 18% Canadian Institutional Canada Retail Energy yield companies currently trading at 3.0x EV/EBITDA and 2.8x cash flow multiple premium to non-dividend paying or low yield senior 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 and reduced capital spending improved sustainability Continue to review in context of commodity prices, capital spending, costs and debt levels * BMO Capital Markets, December 2,

43 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 42

44 Enerplus Share Ownership Investor Composition Geographic Composition Total Retail 69% 23% 13% 18% Total Institutional 31% 35% 65% 46% US/Intl Institutional US/Intl Retail Canadian Institutional Canada Retail Canada US and Other As of November 30, 2012 As of Oct 31,

45 Disclaimers 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. 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, 2011, 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, 2011 ("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. 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. 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. 44

46 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 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. 45

47 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' Annual Information Form 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. 46

48 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 47