Bank of America Merrill Lynch 2012 Global Energy Conference November 2012

Transcription

1 The Game Plan Bank of America Merrill Lynch 2012 Global Energy Conference November 2012

2 Corporate Overview Focused on delivering a combination of moderate organic growth and income to investors Current yield ~8% Own a portfolio of oil and gas properties in some of the best resource plays in North America: early stage assets that offer scope and scale as well as future option value producing assets that generate steady cash flow and offer development opportunity Maintain a strong financial position 1

3 Corporate Profile Ticker Symbol (TSX & NYSE) ERF Enterprise Value (1) $3.5 billion Average Daily Trading Value (through Q3 2012) $49 million 2012E Average Daily Production 82,000 BOE/day 2012E Exit Production 85,000 88,000 BOE/day Oil and Liquids Weighting ~50% Canada/US 66%/34% 2012E Capital Spending $850 million Oil and Liquids Weighting ~75% Q Debt to Trailing 12 Months Funds Flow 1.9x Proforma Manitoba asset sale 1.5x 1. Market Cap. at November 9, 2012 plus September 30, 2012 net debt of $1,119 million less $220 million proforma Manitoba asset sale expected to close late December 2

4 Our Assets 2012E Production Waterfloods 20% Montney, Stacked Mannville and Duvernay Waterfloods Tight Oil Other Oil 23% 6% 24% 18% 9% Deep Gas Marcellus Shale Gas Marcellus Shale Other Gas Bakken/Three Forks 3

5 BOE/day Delivering Organic Production Growth 90,000 80,000 70,000 60,000 73,245 77,221 79,190 82,108 81,573 85,000 88,000 Adjusted annual production guidance to 82,000 BOE/day in 2012 due to slow down in Marcellus activity Expected annual growth of 9% 50,000 40,000 30,000 20,000 Adjusted exit production guidance to 85,000 to 88,000 BOE/day Expected exit growth of 4-7% 10,000 - Q Q Q Q Q Exit Oil growth of 16% since Q Oil Gas 4

6 Improved Financial Flexibility Unutilized Capacity $693MM Debt composition* Senior Notes US$744MM & CAD$70MM Bank Debt $307MM Strategic steps taken in 2012 to manage our balance sheet: $330 million equity issue in February $405 million private placement of long-term debt in May 7 to 12 year terms at 4.4% Dividend reduced to $0.09/share Implemented stock dividend program Laricina equity position sold in August for $141 million Pending sale of non-core Manitoba assets for $220 million expected to close in December $1.0 billion bank credit facility Undrawn ~$693MM* * Q outstanding debt does not include expected proceeds from Manitoba asset sale 5

7 % of net after royalty production % of net after royalty production Protecting our Cash Flow 100% Crude Oil Hedge Positions* 100% Natural Gas Hedge Positions* 80% 80% 60% 60% 40% 63% 58% 40% 20% 0% % 0% 7% 17% Combination of swaps and purchased puts averaging US$96.17.bbl Fixed price swaps averaging US$100.84/bbl Costless collars in place with floor of $2.12/Mcf and ceiling of $2.91/Mcf Combination of swaps and purchased puts averaging $3.31/Mcf * Based on weighted average price (before premiums), average annual production (excluding impact of Manitoba asset sale) assumptions of 82,000 BOE/day for 2012 and 2013, less royalties of 21% 6

8 Fort Berthold Leads the Charge in Oil Growth Current Operated and Non-Operated Locations Key Facts Net Acreage (90% WI) ~70,000 (110 sections) 2011 P+P Reserves 55.4 MMBOE 2011 Contingent Res. Est. 49 MMBOE Future Drilling Locations Q3 Production 12,800 BOE/day Concentrated, top tier land position in North Dakota Bakken and Three Forks Average ~90% working interest Recent QEP Energy $1.4 billion purchase of adjacent/overlapping Bakken acreage position indicates positive valuation comparison Production growth potential to over 20,000 BOE/day over next 3-4 years 7

9 Fort Berthold Operations Update Currently have 66 net operated wells on production with two thirds tied in to gathering system Expect to have 4 more wells producing by year end Reduced size of fracs and amount of fluid/proppant pumped per stage to reduce costs, however drop in performance did not substantiate cost savings Current completions reverting back to stages, 90,000 lbs of proppant per stage across 9,800 foot lateral length Costs ~$5 million to drill and ~$6.5 million complete long hz well before facilities or tie-in, in line with non-op activity Greater confidence in prospectivity of Three Forks with 14 wells on production 4 wells with more than 6 months production tracking type curve (70% of a Bakken long) Best well is on pace to produce 100,000 bbls in 1st year, comparable to Bakken type well 2012 drilling program primarily single well pads to manage lease expiries 2013 expect a 2 rig program with a reduced capital program resulting in modest production growth 8

10 Cumulative Production (mbbls) Cumulative Production (mbbls) Fort Berthold Well Results To Date 180 Short Well Performance Long Well Performance wells wells Months wells wells Months Bakken Cumulative Type Curve Bakken Cumulative Actuals Bakken Cumulative Type Curve Bakken Cumulative Avg Actuals Three Forks Cumulative Actuals Three Forks Cumulative Actuals 9

11 Rate of Return* Fort Berthold Economics 80% 70% 60% Bakken Long Well 800 Mbbl EUR WTI Strip Price - Oct 11, % 40% 30% 20% Three Forks Long Well 560 Mbbl EUR 10% 0% $10 $11 $12 $13 $14 $15 Capital ($ millions) * Economics include associated gas, before tax in US dollars with Bakken differential of US$17.00/bbl, declining to $13.00 in 4 years. Royalties average 19.5%, plus state production and extraction tax of 5% for first 5years, followed by 9% thereafter 10

12 BOE/day Delivering Organic Oil Growth at Fort Berthold 14,000 12,000 10,000 8,000 6,000 4,000 2,000 - Q Q Q Q Q Q Q

13 Low Decline Canadian Waterflood Assets Key Facts OOIP* ~1.2 billion barrels (net) P+P Reserves (YE 2011*) Recovery to date* 22% Best Est. Contingent Resources* Average Oil Quality Q Production 82 million barrels net (26% recovery) 53.5 million barrels 30 API ~16,769 BOE/day Significant future drilling potential as well as enhanced oil recovery opportunities Moderate growth outlook of ~5% per year * As at Dec. 31, 2011 and updated to reflect Manitoba asset sale transaction expected to close December

14 MBOE/day Stable Crude Oil Production Base from Waterfloods 25 Sold ~2,800 non-core BOE/day Low base decline of ~12% ~50% of net operating income reinvested to maintain production E annual production: ~17,000 BOE/day, +2% from AA 2006 AA 2007 AA 2008 AA 2009 AA 2010 AA 2011 AA 2012e AA 2012e Exit * 2012 production estimates not adjusted for Manitoba asset sale expected to close December

15 Marcellus: Retaining Leases for Future Value Capture 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) 2012 activity driven by focus on lease retention in non-operated counties Bradford, Susquehanna and Lycoming ~80% of drilling activity in 7-11 Bcf areas with IRRs of 15% - 30%* Expect to have close to 2/3 of core nonoperated acreage held by production by year-end Reducing acreage positions in operated areas in Maryland and West Virginia Non-operated on-stream activities delayed due to weak natural gas prices resulting in lower than expected production November 2012 production ~48 MMcf/day, up 90% year to date * Rates of return estimated using Oct 11, 2012 forward prices for NYMEX natural gas 14

16 Cumulative Production (MMcfe) Northeast Pennsylvania Well Performance 2,500 2,000 1,500 1, Producing Days Susquehanna Actuals Bradford Actuals E Lycoming Actuals W Lycoming Actuals 6 Bcf Type Curve 8 Bcf Type Curve 15

17 Rate of Return Marcellus Economics 45% 40% 35% NYMEX STRIP PRICING $ $ $ $ $4.86 $7 mm well cost $8 mm well cost 30% 25% 20% $9 mm well cost 15% 10% 5% 0% EUR (bcf) 16

18 An Abundance of Deep Gas Opportunity Stacked Mannville Potential 70,000 net acres of land (42,000 acres undeveloped) Duvernay Potential 72,000 net acres of undeveloped land Montney Potential 33,000 net acres of undeveloped land Approximately 175,000 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 liquids rich zones 2012 capital focused on delineation Duvernay 1 vertical strat well Montney - 1 vertical strat Stacked Mannville (Wilrich) 2 hz producers Large, long tenure, high working interest land holdings 17

19 Duvernay Emerging as a Top Quality Liquids-Rich Resource Play Key Facts Key Properties Net Acreage Est. OGIP Est. Density Estimated EUR/Well Early Hz Well Cost Willesden Green, AB ~72,000 acres (113 sections) ~65 Bcf/section 4 wells/section 3.5 Bcf ~$15 million 30 day IP ~4.4 MMcf/day Est. Liquids bbls/mmcf (high % condensate) Analogous rock characteristics to the Eagleford Prolific over-pressured Devonian source rock (~56 MPa) We own ~113 net sections (100% W.I.) within the gas condensate window: equivalent thermal maturity and depth to proven liquidsrich Kaybob area 4 well/section development provides us with over 400 future Hz drilling locations Increased industry activity in Willesden Green region providing strong geological control and increased confidence in play Our lands are intersected by major pipelines providing proximal egress options, reduced tie-in costs and numerous options for product marketing Focused on evaluation in 2012 with one vertical strat well drilled in October and 1st Hz planned for Q1 18

20 Duvernay Shale Willesden Green ERF Vt Well W5 RR Oct. 26, 2012 Q ERF Proposed Hz W5 19

21 Why Enerplus? Demonstrating organic production growth Significant inventory of oil and gas opportunities in portfolio to deliver future growth in reserves and production Strong financial position with significant unutilized credit capacity Attractive, more sustainable dividend providing yield of ~8% Compelling valuation relative to asset value and peers 20

22 Supplemental Information The Game Plan

23 MMBOE 175% Organic Reserve Replacement in P reserves increased by 5% MMBOE 47% 53% P Reserves* 322 MMBOE 43% 57% P Reserves* 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 NPV of Fort Berthold oil property up 160% due to success of drilling program Crude Oil and Liquids Natural Gas * Company interest reserves 22

24 $/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 in accordance with Canadian reporting requirements under National Instrument * % of 2P reserve additions attributable to crude oil

25 North Dakota Takeaway Capacity North Dakota Does not include: Enbridge Sandpiper looping of existing line (~200 bbls/d to Superior) or Saddle Butte High Prairie line (~200 bbls/d to Clearbrook) which is not yet approved. 24

26 Bakken Oil Differentials $4 $0 Oil sold into pipeline at Bakken basket price Oil sold into rail -$4 -$8 -$12 -$16 -$20 * Diffs do not reflect cost of trucking Recent benefit of rail deliveries vs. pipeline in 2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Rail and pipeline commitments in place for 8,500 bbls/day in 2012 and 14,000 bbls/day in 2013 ~30% of our US Bakken production transported on rail, ~70% through pipelines ~15% is exposed to LLS pricing As more crude accesses these premium markets, we expect this differential to narrow 25

27 Locations Multi-Year Drilling Inventory at Fort Berthold (Year End 2011) Contingent Resource Locations YE 2011 Booked Net P+P-UD Locations Bakken Contingent Net Locations Three Forks Contingent Net Locations Total Booked Reserves & Contingent Resource Locations 4 to 6 years of drilling inventory assuming 20 to 30 wells drilled per year Additional upside possible from increased density and land utilization 26

28 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 Early Learnings: Estimated Recovery: 2.7 million bbls/dsu 12-16% recovery factor CR estimate assumes land utilization of: Bakken 90% Three Forks 35% Communication occurring between the Bakken and Three Forks during completion; potentially during production Bakken wells appear to outperform Three Forks contribution? 2 wells/dsu likely underdeveloped ??? Estimated Recovery: 3-4 million bbls/dsu up to 18% recovery factor Bakken OOIP: 9-12 million bbls/dsu Three Forks OOIP: 8-10 million bbls/dsu 27

29 Stacked Mannville Key Facts Key properties Net Acreage (acres) Pine Creek to Hanlan ~70,000 acres (110 sections) 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 Successful 2012 well tests support future development of this asset Contiguous land blocks in highly prospective regions Enerplus working interest lands 28

30 Cumulative Production (MMcf) Deep Gas: 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 29

31 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 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 30

32 Deep Gas: 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 31

33 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 SDP participation is completely optional Replaced Canadian DRIP Early participation of about 18% of dividends paid Up from 11% for first 5 months of 2012 under old DRIP 32

34 Disclaimers Assumptions All economics contained have been calculated using forward prices and costs as of March 26, 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. 33

35 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. 34

36 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. 35

37 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 36