Peters & Co. 2012 North American Oil & Gas Conference September 11, 2012 The Game Plan Robert J. Waters, Senior Vice-President and Chief Financial Officer
Corporate Profile Ticker Symbol (TSX & NYSE) ERF Enterprise Value (1) $4.3 billion Average Daily Trading Value (2012 YTD) $50 million 2012E Average Daily Production 83,500 BOE/day 2012E Exit Production 88,000 BOE/day Oil and Liquids Weighting ~50% 2012E Capital Spending $850 million Q2 2012 Debt to Trailing 12 Months Funds Flow 2.0x 1. Market Cap. at September 7, 2012 plus June 30, 2012 net debt of $1,152 million 1
Our Assets 2012E Production Montney Wilrich/Stacked Mannville Waterfloods Lloydminster Medicine Hat Glauc C Ratcliffe Viking Cardium Tight Oil 23% Waterfloods 20% 18% Deep Gas Duvernay Other Oil 6% 24% 9% Marcellus Shale Gas Marcellus Shale Other Gas Bakken/Three Forks 2
BOE/day Delivering Organic Production Growth 2012 Forecast: 90,000 80,000 70,000 60,000 50,000 40,000 30,000 Annual average daily production: 83,500 BOE/day ~11% expected growth over 2011 AA Exit production: 88,000 BOE/day 20,000 10,000 - Q3 2011 Q4 2011 Q1 2012 Q2 2012 2012 AA 2012 Exit Oil Gas ~7% expected growth over 2011 exit Oil and liquids production approaching 50% $850 million capital program 3
Financial Flexibility Unutilized Capacity $819MM Debt composition* Senior Notes US$753MM & CAD$70MM Bank Debt $181MM Debt/funds flow ratio at June 30, 2012 was 2.0x Sold shares in Laricina in August for $141MM** Issued $405 million of private placement long term debt in May 7 to 12 year terms at 4.4% $1.0 billion bank credit facility Undrawn ~$680MM end of Q2 (~$820MM proforma Laricina) Monthly dividend reduced to $0.09/share Implemented stock dividend program Additional flexibility through sale and/or joint venture of a portion of undeveloped land and possible sale of other non-core producing assets Active hedging program reduces impact of price volatility * June 30, 2012 proforma Laricina transaction ** Proceeds are net of taxes and agent fees 4
Our Operational Focus in 2012 Execution at Fort Berthold, ND Reduce cycle times on new wells Reduce downtime 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 5
Fort Berthold Leads the Charge in Oil Growth Current Operated and Non-Operated Locations Key Facts Net Acreage (90% WI) ~76,000 (119 sections) 2011 P+P Reserves 55.4 MMBOE 2011 Contingent Res. Est. 49 MMBOE Future Drilling Locations 130+ 2012 Q2 Production 11,700 BOE/day Concentrated, top tier land position in North Dakota Bakken and Three Forks Invested $276 million in first half of 2012, drilled 16.5 net wells (82% long HZ) Increased operated and non-operated activity resulting in higher production and spending Expect to drill another 12-14 net wells in remainder of 2012 6
BOE/day Delivering Organic Oil Growth at Fort Berthold Well results continue to meet our expectations 12,000 10,000 8,000 6,000 4,000 2,000 - Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Bakken long type well: EUR: 905 MBOE Oil 800 Mbbls Gas 330 MMcf NGLs 50 Mbbls Continue to optimize frac design Both Bakken and Three Forks development potential across our leases Continue to expect production growth to 20,000-25,000 BOE/day 7
Fort Berthold Bakken Economics Bakken Long Laterals 9,500 ft. 20-24 frac stages, $12 MM/well* Type Curve EUR: 905 MBOE Oil Gas NGLs 800 Mbbls 330 MMcf 50 Mbbls IRR 48% Net Present Value (10%)* Payout Period $11.5 million 2.0 years Recycle Ratio 3.1x Recent QEP Energy $1.4 billion purchase of adjacent/overlapping Bakken acreage near our Fort Berthold property provides very positive valuation comparison Economics are before tax in US dollars based on 2013 WTI US$91.78/bbl with Bakken differential of US$17.00/bbl. Royalties average 19.5%, plus state production and extraction tax of 8.5% * Drilling & completion $11.5 million plus $0.5 million tie-in 8
Canadian Waterflood Assets Key Facts OOIP ~1.6 billion barrels (net) P+P Reserves (YE 2011) 90 million barrels net (26% recovery) Recovery to date 21% Best Est. Contingent Resources 56.3 million barrels IOR Improved Oil Recovery (Secondary recovery) EOR Enhanced Oil Recovery (Tertiary recovery) Average Oil Quality 2012E Annual Production 30 API ~17,000 BOE/day 20% of total Potential to grow by ~5% per year through IOR/EOR 2012 YTD - spent $69 million on optimization and polymer projects Focus on: Med Hat Glauc C Lloydminster Ratcliffe Cardium 9
MBOE/day Stable Crude Oil Production Base from Waterfloods Low base decline of ~12% 25 20 Sold ~2,800 non-core BOE/day ~50% of net operating income reinvested to maintain production 15 10 5 0 2005 AA 2006 AA 2007 AA 2008 AA 2009 AA 2010 AA 2011 AA 2012e AA 2012e Exit ~340 net locations to unlock potential value of our assets 2012E annual production: ~17,000 BOE/day, +2% from 2011 10
Attractive Valuation $30 $25 $20 $15 $10 $5 $0 Current share price ~$15.75 Range of NAV Estimates High: $28.88 Average: $19.41 Low: $14.52 Recent trading price of ~$16/share, trading at ~80% of NAV estimates 14 analysts have an average NAV estimate of $19.41/share Annualized dividend yield of ~7% based on $0.09/share monthly dividend As of August 2012 11
Outlook Delivering organic reserve replacement and production growth Good mix of early stage, high growth, and mature oil and gas properties with abundance of growth opportunities Liquids focused capital spending program: Production share of oil and liquids ~50% by end of 2012 Plan to manage debt levels in the context of weak natural gas prices with sale or JV of undeveloped land and potential divestment of noncore producing properties Objective is to deliver competitive total return comprised of sustainable growth and income Enerplus is trading at an attractive valuation relative to asset value and peers 12
Disclaimers Assumptions All economics contained have been calculated using forward prices and costs as of March 26, 2012. 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 51-101 adopted by the Canadian securities regulators ("NI 51-101"), 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 51-101 and do not have a standardized meaning under NI 51-101. 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 51-101, are contained within our Annual Information Form for the year ended December 31, 2011 ("our AIF") which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. 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 www.sec.gov. 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, 2011. 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. 13
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 www.sedar.com and a copy of the Form 40-F which is available under our EDGAR profile at www.sec.gov. 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. 14
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. 15
Investor Relations Contacts Jo-Anne M. Caza Vice President, Corporate & Investor Relations 403-298-2273 jcaza@enerplus.com Garth Doll Manager, Investor Relations 403-298-1218 gdoll@enerplus.com 1-800-319-6462 investorrelations@enerplus.com www.enerplus.com The Dome Tower Suite 3000, 333 7th Ave SW Calgary, AB Canada T2P 2Z1 16