Bank of America Merrill Lynch 2014 Energy Conference

Transcription

1 ERF: TSX & NYSE Bank of America Merrill Lynch 2014 Energy Conference November 13, 2014

2 Forward Looking Information Advisory FORWARD-LOOKING INFORMATION AND STATEMENTS This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", guidance, "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", budget, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this presentation contains forward-looking information pertaining to the following: expected 2014 and 2015 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged; our drilling program including future development and drilling locations and plans, the results from our drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; future efficiencies and reserves and production growth; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating costs; capital spending levels in 2014 and its impact on our production level; potential future asset impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. taxes; future funds flow levels; future debt and working capital levels and debt-to-funds-flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected proceeds therefrom and production volumes associated therewith. The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information 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 realized prices for Enerplus products; 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, incentive programs 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; constraints on, or unavailability of, adequate pipeline and transportation capacity; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F described below and under Risk Factors and Risk Management in our MD&A for the year ended December 31, 2013). The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions made by Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our 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 our reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. We believe 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 contained in this presentation speaks only as of the date of this presentation, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws. 1

3 Advisories Assumptions All amounts are stated in Canadian dollars unless otherwise specified. Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent This presentation contains references to "BOE" (barrels of oil equivalent) and "Bcfe" (billion 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 Bcfes. BOEs and Bcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively. Non-GAAP Measures In this presentation, we use the terms "funds flow", free cash flow, capital efficiency, and recycle ratio as measures to analyze operating performance, leverage and liquidity. Funds flow is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. Debt to funds flow ratio is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The debt to funds flow ratio is calculated as total debt net of cash, divided by a trailing 12 months of funds flow. Adjusted payout patio is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. We calculate our adjusted payout ratio as dividends to shareholders, net of our Stock Dividend Program ( SDP ) proceeds, plus capital spending (including office capital) divided by funds flow. Free cash flow is calculated as net operating income (netback) less capital expenditures. Capital efficiency is calculated as the change in production from the fourth quarter of the previous year to the fourth quarter of the current year divided by total capital expenditures from the fourth quarter of the previous year up to and including the third quarter of the current year. A recycle ratio is calculated as finding and development costs divided by operating netback. Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow", "capital efficiency, and recycle ratio 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 U.S. GAAP and do not have a standardized meaning prescribed by U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. Presentation of Production and Reserves Information Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under IFRS and Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. In order to continue to be comparable with our Canadian peer companies, the summary results contained within this presentation presents our production and BOE measures on a before royalty company interest basis. In addition, initial test results and production performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate recovery. All production volumes and revenues presented herein 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 Standards of Disclosure for Oil and Gas Activities (NI )), being 2

4 Advisories 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, 2013, includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI , is contained within our Annual Information Form for the year ended December 31, 2013 ("our AIF") which is available on our website at and under our SEDAR profile at Additionally, our AIF forms 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 as part of our Form 40-F on EDGAR concurrently with this presentation for more complete disclosure on our operations. Discovered Petroleum Initially-In-Place Discovered Petroleum Initially-In-Place ( PIIP ) is that quantity of petroleum that is estimated to be contained in known accumulations prior to production. The recoverable portion of discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable. Discovered Original Oil in Place ( OOIP ) is not defined in NI and does not have a standardized meaning under NI Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP for our North Dakota assets were provided by an independent estimate by McDaniel & Associates dated June 9, 2014 and as of June 1, Discovered OOIP pertaining to our waterflood assets are estimates by internal qualified reserves evaluators, combined for all core waterfloods. Contingent Resource Estimates This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. The estimates of contingent resources included in this presentation pertaining to Fort Berthold and Canadian Gas-Deep Basin properties were evaluated by Enerplus and audited by independent reserve evaluators, McDaniel & Associates. The estimates of contingent resources included in this presentation pertaining to the U.S. Core Gas-Marcellus were evaluated by independent reserves evaluators, Netherland, Sewell & Associates. The estimates of contingent resources included in this presentation pertaining to Canadian Waterflood Assets were evaluated by internal qualified reserves evaluators. "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 economics, 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. All of our contingent resources estimates are economic using established technologies and under current commodity price assumptions used by our independent reserve evaluators. 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 resources estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered. The contingent resources estimate pertaining to Fort Berthold is effective as of June 1,2014. All other contingent resources estimates are effective as of December 31, A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. For additional information regarding the primary contingencies which currently prevent the classification of our disclosed contingent resources associated with our Marcellus shale gas properties, our Fort Berthold properties, our Wilrich natural gas properties and a portion of our Canadian crude oil properties as reserves, and the positive and negative factors relevant to the contingent resource estimates, see our AIF, a copy of which is available under our SEDAR profile at and our Form 40-F, a copy of which is available under our EDGAR profile at 3

5 Advisories See "Non-GAAP Measures" above. Finding & Development ( F&D )and Finding, Development & Acquisition ( 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 proved 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 proved plus probable future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs related to its reserves additions for that year. FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated proved 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 proved plus probable 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 and net acquisition costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding, development and acquisition costs related to its reserves additions for that year. See "Non-GAAP Measures" above. NOTICE TO U.S. READERS The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period. Additionally, the SEC prohibits disclosure of oil and gas resources in SEC filings, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see Contingent Resource Estimates above. 4

6 Enerplus Proven Strategy Disciplined Capital Allocation Strong Financial Position Sustainable, Organic Growth & Income Robust, economically grounded capital allocation Capital efficiency target of <$30,000 BOE/day Debt-to-funds flow ratio of 1.3x* $1 billion credit line virtually unused* Significant hedge positions in Q and 2015 Significant organic drilling inventory 13% per share production growth in 2014 Long-term growth target of 5% 10% Dividend yield ~6.5% *As at September 30,

7 BOE per Share $ Per Share Strong Per Share Growth Production/share Funds Flow/share $3.29 $3.76 $ E* E** * Based on mid-point of revised 2014 production guidance of 103,000 BOE/day and average shares outstanding. ** Analyst consensus at October 28,

8 Sustainable Growth & Dividend Strong funds flow growth supporting sustainable dividend E Funds Flow (MM) $645 $754 $854 (1) Capital Expenditures (MM) $853 $681 $830 Net Acquisitions & Divestitures (MM) ($91) ($120) ($208) (2) Dividends (MM) $302 $217 $220 SDP Proceeds (MM) ($43) ($46) ($20) Adjusted Payout Ratio (APO) 174% 114% 120% (3) APO, net of A&D 158% 97% 96% D/FF ratio 1.7x 1.4x 1.3x (3) 1) Analyst consensus at October 28, ) At November 6, ) At September 30, Funds flow used for APO calculation is based on analyst consensus at October 28,

9 Q Results Continued Performance Low-end of production guidance increased by 2,000 BOE/day 102, ,000 BOE/day annual average estimate in 2014, despite the sale of 3,500 BOE/day of non-core divestments Non-core divestments two new transactions completed 3,100 BOE/day sold for proceeds of $91 million YTD proceeds from divestments of over $200 million Capital spending increased as a result of net proceeds from divestments Modest capital increase of $30 million to $830 million Continued productivity improvements in key growth areas Fort Berthold YTD avg 30 day IP rate 20% above high type curve estimate Marcellus 25% capital efficiency improvement year-over-year 8

10 Funds Flow Protection WTI Crude Oil Hedge Positions* Natural Gas Hedge Positions* Rest of 2014 Rest of % 51% 10% AECO Swaps C$4.25/Mcf US$95.29/bbl 11% NYMEX Collars US$ $5.08/Mcf 64% 28% NYMEX Swaps US$4.14/Mcf *** 12% C$ % 72% 2015 US$93.68/bbl ** 25% NYMEX Swaps US$4.21/Mcf 38% 3% Q1 NYMEX Collars US$ $5.53/Mcf * As of Oct 22, 2014, based on weighted average price (before premiums), assuming mid-point annual average production of 103,000 BOE/day for 2014 & 2015, less royalties of 23%. ** Include 6% (2000 bbls/day) protected at $93.64/bbl with upside participation above $94.00/bbl *** Includes 9% (25 MMcf/day) protected at $4.17/Mcf with upside participation to $5.00/Mcf. 9

11 Core Areas U.S. Gas 10

12 U.S. Core Oil: Fort Berthold, North Dakota Key Facts Discovered OOIP Discovered OOIP (W.I.) Net Acreage 2P Reserves at Dec 31, 2013 Best Est. Economic Contingent Resources June 1, MMbbls/1280 DSU 1.5 billion bbls 73,000 acres (114 sections) 105 MMBOE 136 MMBOE ~90% W.I. Bakken Three Forks Drilling/ WOC Future Net Drilling Locations PUDs Contingent Resources Q Production Net Locations Drilled to Date 330 wells (98) (232) 22,400 BOE/day 125 wells (93 Bakken/32 Three Forks) 2014 Focus: Productivity improvements through: Down spacing tests Delineation of Lower Three Forks Completion optimization 11

13 MBOE/day MMBOE Fort Berthold Delivering Growth Annual Production Reserves P: P: P: E P: P: P: P: P: 49.6 Total Proved Probable 2014E annual production growth of ~30% Replaced 400% of 2013 production adding 24.9 MMBOE of reserves at F&D cost (incl. FDC) of $19.74/BOE Three year F&D cost of $21.56/BOE *Free cash flow is calculated as NOI less capital expenditures. 12

14 Fort Berthold: 127% Increase in Drilling Inventory Locations Original View 4 wells/ DSU New View Avg. 7 wells/ DSU Bakken Long Three Forks Long Bakken Short Three Forks Short new locations added Two thirds of locations are long laterals Average 7 wells per spacing unit with maximum of 8 wells per unit Average EUR per well Long 625 Mbbls/750 MBOE Short 320 Mbbls/385 MBOE Total Net Future Drilling Locations* * Includes undeveloped reserves and contingent resources locations. 13

15 Improving Productivity through Completion Enhancements 14

16 Capital Efficiency ($K/BOE/day) Fort Berthold: Improving Capital Efficiencies* 25,000 20,000 15,000 $20,500 $18,000 $15,500 $11,500 $11,000 Reduction in well costs and significant increase in IP rates driving top quartile capital efficiencies 10,000 5,000 $8,000 On-going focus on completion evolution and cost improvement Ceramic: Stages (~275 lbs/ft) 2013 Ceramic: 28 Stages (~325 lbs/ft) 2013 White Sand: 28 Stages (~750 lbs/ft)) 2013 White Sand: Stages (~750 lbs/ft) 2013 White Sand: Stages (~1000 lbs/ft) 2014 White Sand: Stages (~1000 lbs/ft) * Capital efficiency based upon 30 day initial production rates 15

17 Fort Berthold Completion Performance Improving Economics* Old Type Curve New Type Curve High EUR Low EUR High EUR Low EUR 800 Mbbls 500 Mbbls 800 Mbbls 530 Mbbls (950 MBOE) (600 MBOE) (950 MBOE) (635 MBOE) 30 Day Cum Prod (bbls) 23,000 15,000 43,000 31,000 1st Year Cum Prod (bbls) 155,000 98, , ,000 NPV 10% ($MM) $11.08 $2.34 $13.76 $4.67 IRR Btax (%) 45% 15% 80% 30% Payout (Yrs) Recycle Ratio Capital ($MM) * Assumes US$85/bbl WTI flat crude oil price and US$4.00/Mcf NYMEX natural gas price; based on long Bakken horizontal wells. 16

18 First 6 Calendar Month Liquids Production* (bbls) Fort Berthold Completions Enhancements Leading to Best in Basin Well Results First Six Calendar Months E+ Best Bakken E+ Best Three Forks Enerplus wells drilled without high volume completions Enerplus wells drilled with high volume completions volume completions Well Count * Long horizontal wells only (>6,000 lateral). Data set ~6,300 wells, at November 1,

19 Low Decline Canadian Waterflood Assets Key Facts Discovered OOIP (W.I.) 1.3 billion bbls Recovery Factor * to Date 24% 2P Reserves at Dec 31, 2013 Best Est. Economic Contingent Resources Dec 31, 2013 Future Net Drilling Locations Q Production 87 MMBOE 59 MMbbls EOR & IOR 160 wells 20,000 BOE/day Average Decline Rate 14% Core area representing almost half of corporate liquids production Lower growth profile with low decline Primary, secondary and tertiary oil recovery opportunities * Estimated by internal qualified reserves evaluators. Represents the combined production for all core waterfloods divided by the combined discovered OOIP for all core waterfloods. 18

20 $ Million Free Cash Flow from Waterflood Assets $350 $300 $250 $200 $150 $100 NOI: $266 $124 NOI: $287 $137 53% 52% NOI: $301 $179 41% NOI: $320 $172 46% NOI: $272 $77 72% Significant free cash flow generation with reinvestment around 55% annually 2014 capital higher with Brooks program $50 $ E* Capital Free Cash Flow * Based on September 30, 2014 forward curve and 2014 corporate differential assumptions. Free cash flow is calculated as NOI less capital expenditures; adjusted for acquisitions and divestitures. 19

21 Thickness U.S. Core Gas: Marcellus Enerplus Land Key Facts Marcellus Well Net Acreage 2P Reserves Dec 31, 2013 Best Est. Economic Contingent Resources Dec 31, 2013 Future Net Drilling Locations Q Production 53,300 acres 601 Bcf 1,340 Bcf 240 wells 187 MMcf/day 28% W.I. Pennsylvania Concentrated, non-op position in NE Pennsylvania Marcellus Q3 production represents 52% of corporate natural gas volumes 60% of core acreage held by production 20

22 MMcf/day Bcf of Natural Gas Marcellus Delivering Growth 200 Annual Production Reserves 2P: E 2014 >90% production growth forecast P: 117 1P: 52 2P: 154 1P: 93 2P: 225 1P: Total Proved Probable 2013 proved plus probable reserves increased by 168% 50% of corporate 2P natural gas reserves P F&D of $0.58/Mcf & FD&A of $0.91/Mcf 1P:

23 Marcellus: Superior Dry Gas Performance and Competitive Economics Tighter stage spacing and increased proppant continues to improve performance Gross On-Streams EUR EUR EUR EUR US$ 4.50/Mmbtu 8 Bcf 12 Bcf 13 Bcf 16 Bcf IP30, MMcf/d IRR, % PV10, $MM Capital, $MM US$ 4.00/Mmbtu IRR, % PV10, $MM The 13 BCF EUR case reflects infrastructure constrained production, with lower IP30 Differentials: 2014: -$ : -$ : -$ & beyond: -$

24 Core Canadian Natural Gas Deep Basin Duvernay 85,000 net acres of undeveloped land, 100% WI Core growth area with approximately 450 potential net future drilling locations in the Wilrich and Duvernay 160,000 net acres of high working interest land Stacked Mannville 76,000 net acres of land (60,000 net acres of land in the Wilrich, majority 100% WI) Successful drilling results to date in Wilrich moving to development Advancing appraisal on Duvernay lands 23

25 Duvernay Shale Willesden Green R12W5 R11W5 R10W5 R9W5 R8W5 R7W5 R6W5 R5W5 R4W5 R3W5 ENERPLUS Vt W5M Rig Released: 10/23/2013 Cored, logged and prepped for future re-entry ENERPLUS Vt W5M Rig Released: 10/26/2012 Cored and logged ENERPLUS Hz W5M On production 10/2014 IP30 ~700 Boepd (58% liquids) Producing Wells Drilled Wells Locations ENERPLUS Vt W5M Rig Released: 8/30/2013 Cored, logged and reentered ENERPLUS Hz W5M On production 6/2014 IP30 ~535 Boepd (30% liquids) 85,600 net acres (100% W.I.) Core analysis from 4 vertical tests supports a range of free condensate yields across a significant portion of acreage 2 horizontal wells completed and placed on production to-date with positive results W5M average 30 day IP rate of 535 BOE per day including 2.24 MMcf per day of sales gas with 162 barrels per day of total liquids, 53% condensate W5M average 30 day IP rate of 700 BOE per day, including 1.75 MMcf per day of sales gas, with 410 barrels per day of liquids, roughly 85% condensate Future development at 3-4 wells per section provides Hz potential drilling locations R12W5 R11W5 R10W5 R9W5 R8W5 R7W5 R6W5 R5W5 R4W5 R3W5 Continued evaluation of well results and focus on improving well costs 24

26 Our Competitive Advantage Focused portfolio in top tier resource plays: Bakken/Three Forks, Marcellus, Deep Basin & Waterfloods Continued focus on capital discipline delivering 13% production/share growth in 2014 with a target capital efficiency of <$30,000/BOE/day Low corporate decline rate Significant inventory of economic growth prospects: ~830 future drilling locations* & sizeable upside Affordable growth supported by a strong balance sheet Delivering profitable growth with an attractive yield * 2P reserves and contingent resource locations at December 31, 2013; Fort Berthold contingent resource assessment completed June 1,

27 Supplemental Information

28 Significant Organic Growth Potential Core Waterfloods Primary Drilling Secondary Recovery Tertiary Recovery Marcellus 15 years 160 Locations 240 Locations 330 Locations 100 Locations Fort Berthold 16 years Deep Basin (Wilrich) 10 years Additional Upside: Fort Berthold Downspacing opportunities Duvernay 85,000 net acres prospective for natural gas liquids Torquay Canadian Three Forks play 92,160 acres 144 sections (100% W.I.) Sleeping Giant (Montana) Possible enhanced oil recovery opportunity * 2P reserves and economic contingent resources locations at December 31, 2013 and as at June 1, 2014 for Fort Berthold economic contingent resources assessment. Based on current development plans. 27

29 MBOE/day MMBOE Demonstrated Growth Annual Production Reserves ** % 40% 43% 47% 49% 53% 55% % 47% E* Oil & Natural Gas Liquids Natural Gas Liquids Crude Oil Natural Gas * Based upon mid-point of 2014 production guidance of 102, ,000 BOE/day. ** Proved plus probable company interest reserves at December

30 $/BOE $/BOE Competitive Reserve Addition Costs F&D Costs* FD&A Costs* $30 $25 $26.26 $24.21 $30 $25 $22.92 $20 $15 $10 $ year: $19.25 $20 $15 $10 $17.89 $ year: $14.66 $5 $5 $ $ * Based on proved plus probable company interest reserves at December 31, including future development costs. FD&A is defined as finding, development & acquisitions (net of dispositions). 29

31 2014 Funds Flow Sensitivities 2014 Sensitivities Est. effect on 2014 Funds Flow ($ Million) Est. effect on 2014 Funds Flow per Share ($/share) Change of $5.00/bbl WTI crude oil $5.5 $0.03 Change of $0.50/Mcf NYMEX natural gas $8.0 $ 0.04 Change of 1,000 BOE/day production for rest of year $2.5 $0.01 Change of $0.01 in the US$/CDN$ exchange rate $1.9 $0.01 * The sensitivities above reflect our forecasts, outstanding commodity contracts, approximately million outstanding shares, and are based on forward markets as at October 22,

32 Operated Light Oil Assets in the Williston Basin 2014E Production: 28,000 BOE/day Sleeping Giant 20% Fort Berthold 80% P Reserves*: 131 MMBOE Sleeping Giant (Elm Coulee) Fort Berthold Sleeping Giant 20% Dunn Enerplus lands 80% Fort Berthold * Company interest reserves at December 31,

33 Boe/day Consistent Production Growth in Fort Berthold 30, E AA: 22,000 BOE/day 25, AA: 16,500 BOE/day 20,790 22,359 25,500 20,000 15,000 14,576 15,169 18,035 18,206 18,310 10,000 5,000 - Q Q Q Q Q Q Q Q (Est) FTB Production 2013 Annual Annual Average Average Production Production Q production has grown 24% since the same period in 2013 Expect to bring 5.6 net wells on-stream in Q4 32

34 Fort Berthold: 250% Increase in Contingent Resources Original Assumption 2014 Evaluation Increase Discovered OOIP per DSU* Bakken TF1 TF2 Total 8 12 MMbbls 8 10 MMbbls n/a million bbls 8 16 MMbbls MMbbls 2 20 MMbbls million bbls 4 20 MMbbls TOTAL WI Discovered OOIP 1 billion bbls 1.5 billion bbls 500 MMbbls 2P Dec. 31, MMBOE 105 MMBOE - Contingent Resources 39 MMBOE 136 MMBOE 97 MMBOE Utilization Assumptions: Bakken TF1 TF2 100% 70% n/a 100% 100% 35% * Per 1,280 acre drilling spacing unit (DSU). 33

35 Fort Berthold Well Density Schematic 6 / 7 Well Density* No Lower Three Forks Stand-Alone Locations 8 Well Density* Lower Three Forks Productive TF 2 &3 Upside** TF3 & Additional TF Wells * Assumes 15% recovery factor. ** Super Unit equivalent to lease line drilling. 34

36 Fort Berthold: Increasing to Average 7 Wells/DSU Enerplus Hognose Successful TF2 Enerplus Butterflies TF2 Drilling 8 Northwest Highest estimate of discovered OOIP Includes TF2 8 well density 6,7,8 Central/West Well density ranging from 6 8 wells depending upon discovered OOIP and TF2 prospectivity Industry TF2/TF3 Planned 6 or 7 Central/South Planned for 6 or 7 well density depending upon discovered OOIP and recovery factor 35

37 Cum. Oil (Mbbls) Fort Berthold: Encouraging Enerplus High Density Tests 300 Snakes Pad 8 Well Density & TF2 Butterflies/Turtles* pad 8 Well Density & TF Snakes Pad Fur Bearers pad 7 Well Density Fur Bearers Pad TF1 Enerplus down spacing test (7 well density) Enerplus down spacing test & TF2 test Enerplus down spacing test & TF2 test Bakken Three Forks Drilling/ WOC Months on Production * Butterflies/Turtles pad on-stream early November 36

38 Oil (Mbbls) US$K Fort Berthold Completion Evolution Increasing Production Rates $350 $300 $250 $200 $150 $100 $319 Completion Costs/Stage $241 $215 $195 $221 $216 Despite larger fracs, the switch to sand and effective cost management has helped reduce completion costs $50 $ BKN TF 30 Day Cum. Oil Significant increase in 30 day cumulative production from high intensity fracs # Wells: 17 Bkn / 6 TF 3 Bkn / 1 TF 2 Bkn / 0 TF 2 Bkn / 2 TF 6 Bkn / 3 TF 2 Bkn / 3 TF 37

39 Peak Calendar Month Cumulative Production* (bbls) Fort Berthold Completions Enhancements Leading to Best in Basin Well Results E+ Best Bakken E+ Best Three Forks Peak Calendar Month Enerplus wells drilled without high volume completions Enerplus wells drilled with high volume completions volume completions Well Count * Long horizontal wells only (>6,000 lateral). Data set ~7,000 wells, at November 1,

40 Fort Berthold U.S. Crude Marketing Available Capacity ~540,000 bbls/day of regional pipe capacity currently available and another 200,000 bbls/day coming into service after 2016 Rail loading capacity is plentiful with > 1.2 MMbbls available at more than 16 unit train facilities Pipe 31% Rail 69% Current take-away capacity exceeds regional production by 60% Enerplus seeks to maintain a balanced approach to marketing commitments 13,500 bbls/day of firm regional egress commitments currently in place 5,000 bbls/day firm commitment made to Sandpiper project to Clearbrook expected in late 2017 or early 2018 * Refers to August 2014 North Dakota and Montana production of ~1.2 MMbbls per NDIC and Montana Board of Oil and Gas Conservation reports. 39

41 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 US$/Mcf Fort Berthold: Natural Gas and NGL Production 7% Fort Berthold (Q BOE/day) 6% Gas and NGLs are gathered and marketed by our gatherer at market netback pricing $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- Oil Gas Liquids 87% Realized Gas Price Ft. Berthold (1300 BTU factor) Nymex Realized natural gas price is higher than NYMEX because of higher heat content Enerplus has been proactively focused on gas conservation ~80% of our wells are connected to gas gathering; increasing by year-end All wells are being equipped with high efficiency flares as back-up in case of disruptions 40

42 S S S S S S S Brooks Overview R14 R13 R12 R11W4 T North T20 Key Facts Discovered OOIP Recovery Factor to Date 27% 2P Reserves at Dec 31, MMbbl 9 MMBOE Best Estimate Contingent Resource Dec 31, MMBOE T T19 Cumulative Oil Production to Date 61 MMbbl E Production 2,750 BOE/day Average Base Decline Rate 12% T T18 Lower Mannville/Basal Quartz (~1,000 m depth) South Potential to drill 60 locations over the next two+ years T T17 Currently running two rigs in Brooks South T R R13 R12 R11W4 100% Working Interest T16 Early production performance has been positive with average results in-line with our type-curve expectations 41

43 MMcf/day Marcellus Production Growth E AA: 190 MMcf/day AA: 95 MMcf/day Q Q Q Q Q Q Q Q (Est) Total Marcellus Production Annual Average Production 42

44 MMcf/day $/BOE/day $ Thousands Marcellus Well Cost & Performance Evolution Total Well Cost 12,000 10,000 8,000 $10,000 $8,000 $7, Day Capital Efficiency 6,000 4,000 2, ,000 7,000 6,000 $7,500 $5, Initial Production 5,000 4,000 $4, , IP30 IP60 IP90 2,000 1, * * 2014 production rates include curtailment. 43

45 Marcellus Sales Price Mix Q Dominion South: 36% TGP Z4 300 Spot: 34% Transco Leidy Spot: 22% Remainder priced at: TETCO M3 (NY), TGP 500 (Tennessee) and TGP Z4 200 (Ohio) Transco Z6 NNY: 3% Regional firm, must-take contracts of ~80 MMcf/day plus ~10 MMcf/day of pipeline capacity out of the region held through 2015, with remainder sold at spot market Executed sales and precedent transportation agreements for up to 80 MMcf/day at Transco Non- New York to backfill our must-take contracts starting in 2016 * Map Source: Kinder Morgan. 44

46 Northeast U.S. Pipeline Projects: >8 Bcf of Projects Planned Project Pipeline Owner Incremental Takeaway (MMcf/day) Destination In Service Rose Lake 300 TGP KM 230 NE* Q Transco - Northeast Connector Transco Williams NE Q Transco - Rockaway Lateral Transco Williams 647 NE Q12015 Columbia East Side Expansion TCO Columbia 300 NE Q Niagara Expansion TGP KM 158 Canada Q ,123 Northern Access 2015 NF Nat Fuel 140 Canada Q Transco - Leidy Southeast Transco Williams 525 Southeast Q Constitution Constitution Williams 650 NE/Canada Q Rock Springs Lateral Transco Williams 192 NE Q Algonquin Incremental Market (AIM) Algonquin Spectra 342 1,506 NE Q Connecticut Expansion TGP KM 72 NE Q Northern Access 2016 NF National Fuel 250 Canada Q Atlantic Sunrise Transco Williams 1,700 Southeast Q Atlantic Bridge Algonquin Spectra 100 NE Q Susquehanna West Expansion TGP KM 145 2,745 NE Q Penn East Project PennEast Pipeline UGI, SJR, NJR, AGL 800 NJ/Non NY Q Northeast Energy Direct (NED) TGP KM 800 1,800 NE Q Diamond East Transco Williams 1,000 NJ/Non NY Q * Internal sources, November

47 Northeast Pa. Marcellus Pipeline Infrastructure Future Takeaway Capacity Production growth could be capped at 1.5 Bcf/day based on the pace of expected pipeline additions in the NE Pa. Marcellus Could see basis relief by 2017/2018 as capacity additions appear to be sufficient to meet this pace of production growth Source: ERF estimates (as of Sep 2014) 46

48 Canadian Gas Deep Basin (Wilrich) Contiguous land blocks in highly prospective regions North Ansell CORE FOCUS - Finishing 2-well pad in Q with partners. Completion and tie-in Q Ansell CORE FOCUS Q capital acceleration - 3-well Wilrich pad development Key Facts Key properties Net Acreage (acres) 2P Reserves Dec 31, 2013 Best Est. Economic Contingent Resources Dec 31, 2013 Future Net Hz Drilling Locations Est. EUR/Well Q Stacked Mannville Production Edson, Ansell, Minehead, Hanlan 60,000 acres (92 sections, majority 100% WI) 62 Bcfe 253 Bcfe >100 wells Bcfe 27 MMcf/day Growth potential to 60+ MMcf/day Ownership in existing infrastructure to support up to 50 MMcf/day 47

49 Wilrich Activity Operated activity for Q Commencement of three-well pad in Ansell Non-operated activity Two-well pad in North Ansell rig release in Q with expected on-stream Q Results from both programs will be evaluated for additional 2015 activity AECO $4.00/Mcf EUR 7 Bcf EUR 6 Bcf Assumptions: Capital: $7MM/well; assumes pad drilling Liquids: 7-10 bbls/mmcf EUR 5 Bcf NPV10 ($MM) $6.7 $5.3 $3.9 IRR (%) Payout (years) IP30 (Mcf/day) 7,600 6,900 6,200 BESC ($/Mcf) $2.23 $2.42 $2.65 AECO $3.50/Mcf NPV10 ($MM) $5.2 $4.0 $2.7 IRR (%) Payout (years)

50 Debt Composition at September 30, 2014 Unused Capacity $942MM Senior Notes* US$966MM CDN$70MM Bank Credit Facility - $1 billion 11 banks in Enerplus bank credit facility Unsecured, covenant-based with current borrowing rate of less than 3% Credit facility matures October 31, 2017 Bank Facility $58MM Senior Unsecured Notes - CDN$1,036 MM Notes are rated NAIC 2 and rank equally with bank credit facility; average interest rate of 5.3% On September 3, 2014 we closed a US$200 million private placement of senior unsecured notes with a 10 year average life at an interest rate of 3.79% *Canadian dollar equivalent of U.S. dollar denominated notes FX rate at September 30, 2014 US/CDN of

51 $ Millions Senior Notes Maturities Average interest rate of 5.3%* $160 $140 $120 $130 $130 $147 $124 $124 $100 $80 $97 $80 $60 $40 $51 $51 $45 $45 $20 $0 $12 $ * US$ amounts converted at US/CDN

52 Enerplus Share Ownership Investor Composition Geographic Composition Total Retail 60% Total Institutional 40% 21% 36% 44% 20% 56% 24% US & Other Retail Canadian Retail US & Other Institutional Canadian Institutional United States & Other Canada As of October 20,

53 Enerplus Board of Directors Elliott Pew, Chairman of the Board (1)(2) Mr. Pew, Chairman of Enerplus, is a co-founder of Common Resources and served as its Chief Operating Officer until the company was sold in May, He is currently a Director for the newly formed Common Resources II located in The Woodlands, Texas. Previously, Mr. Pew was Executive Vice President - Exploration at Newfield Exploration Company in Houston where he led Newfield s diversification efforts onshore in the late 1990 s in addition to leading the company s exploration program, including the formation of the deep water GOM business unit. Prior to Newfield, Mr. Pew was Senior Vice President - Exploration with American Exploration Corp. Mr. Pew is a Geology graduate of Franklin and Marshall College and holds an M.A. in Geology from the University of Texas. David H. Barr, Director (12) Mr. Barr has 38 years of experience in the oil and gas industry, and is President and Chief Executive Officer of Logan International Inc., a company focused on downhole tools and completion services. He was formerly Chairman of the Board of Logan International. He also spent close to 36 years with Baker Hughes in various executive roles, including Group President of numerous divisions and President of Baker Atlas. He currently serves as a Director of ION Geophysical Corporation and Probe Technology Services. Mr. Barr holds a B.S. Mechanical Engineering degree from Texas Tech University. Michael Culbert, Director (3)(9) Mr. Culbert brings over thirty years of diverse experience in the oil and gas industry in North America and is currently the President, Chief Executive Officer and a Director of Progress Energy Canada Ltd. He brings a strong background in business development, economics and strategic planning and holds a Bachelor of Science degree in Business Administration. He currently sits on the Board of Directors of Pacific NorthWest LNG Ltd. and is also a member of the Canadian Association of Petroleum Producers Board of Governors. Edwin V. Dodge, Director (9)(11) Mr. Dodge is currently a corporate director following a 35-year career with Canadian Pacific Railway Limited ("CPR", a Canadian national rail carrier), where he was Chief Operating Officer from 2001 until his retirement in March Prior to 2001, Mr. Dodge held other senior roles with CPR including Executive Vice President of Operations for Canada and the U.S., as well as Chief Executive Officer of a Minneapolis-based railroad. Mr. Dodge holds a Civil Engineering degree and an MBA from the University of Western Ontario. Ian C. Dundas, Director Mr. Dundas became President and Chief Executive Officer of Enerplus on July 1, He joined the company in 2002 as Vice-President of Business Development, with accountability for all corporate acquisition and divestment strategies. In 2010, his role expanded to that of Executive Vice-President. In 2011, his responsibilities were further expanded to include the role of Chief Operating Officer, overseeing the development and execution of the company s operational strategies, strategic planning, marketing, reserves, as well as acquisitions and divestments. As President and Chief Executive Officer, Mr. Dundas is responsible for overall leadership of the strategic and operational performance of Enerplus.

54 Enerplus Board of Directors continued Hilary Foulkes, Director (5)(11) Ms. Foulkes has more than 30 years of experience within the Canadian oil and gas industry focused in the areas of exploration, development and investment banking. She has held executive roles in both investment banking and oil and gas operations, including Executive Vice-President and Chief Operating Officer for Penn West Petroleum Ltd. She is a professional geologist and earned a Bachelor of Science (Honours, Earth Sciences) from the University of Waterloo. Her career highlights include being the architect and lead negotiator of award-winning, multi-billion dollar international joint ventures. James B. Fraser, Director (7)(11) Mr. Fraser has over 35 years of energy industry experience, and was the Senior Vice President for the shale division of Talisman Energy Inc.'s North American operations. From 2006 to 2008, Mr. Fraser was Vice President of operations for the southern division of Chesapeake Energy and prior to this spent over 20 years at Burlington Resources and its predecessor companies, where he held a number of senior positions including North American Exploration Manager. Mr. Fraser holds a MBA from Regis College and a Bachelor of Science in Petroleum Engineering from the Montana School of Mines. Robert B. Hodgins, Director (3)(6) Mr. Hodgins has been an independent businessman since November Prior to that, Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust (a TSX and NYSE-listed energy trust) from 2002 to Prior to that, Mr. Hodgins held the position of Vice President and Treasurer of Canadian Pacific Limited (a diversified energy, transportation and hotels company) from 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited (a TSX and NYSE-listed energy transportation company) from 1993 to Mr. Hodgins received a Bachelor of Arts in Business from the Richard Ivey School of Business at the University of Western Ontario in 1975 and received a Chartered Accountant designation and was admitted as a member of the Institute of Chartered Accountants of Ontario in 1977 and Alberta in Susan M. MacKenzie, Director (7)(10) Ms. MacKenzie has over 25 years of energy sector experience, most recently serving as Chief Operating Officer with Oilsands Quest Inc. in Prior to that, Ms. Mackenzie enjoyed a 12-year career at Petro-Canada where she held senior roles including Vice-President of Human Resources and Vice President of In Situ Development & Operations. Ms. MacKenzie was also with Amoco Canada for 14 years in a variety of engineering and leadership roles in natural gas, conventional oil and heavy oil exploitation. Ms. MacKenzie holds a Bachelor of Engineering (Mechanical) degree from McGill University, an MBA from the University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA). Donald J. Nelson, Director (3)(9) Mr. Nelson has over 40 years of experience in the oil and gas industry, and is the president of Fairway Resources Inc., a private consulting services firm. Prior to this, Mr. Nelson was with Summit Resources from 1996 to 2002, until its acquisition by Paramount Resources Ltd., where he held the position of Vice President Operations from 1996 to 1998 and President and Chief Executive Officer from 1998 to He currently serves as Director for Perpetual Energy Inc., Keyera Corp., as well as three other private companies. Mr. Nelson is a Professional Engineer, a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and of the Society of Petroleum Engineers.

55 Enerplus Board of Directors continued Glen D. Roane, Director (4)(5) Mr. Roane is a corporate director and currently serves as a director of Enerplus, Badger Daylighting Ltd., Logan International Inc., SilverBirch Energy Corporation and the GBC American Growth Fund. Mr. Roane is also a member of the Alberta Securities Commission. Previously he served as a board member of many TSXlisted companies and private companies including Repap Enterprises Inc., Ranchero Energy Inc., Forte Resources Inc., Valiant Energy Inc., Maxx Petroleum Ltd., UTS Energy Corporation, Destiny Resource Services Ltd., NQL Energy Services Inc., Severo Energy Ltd., Flexpipe Systems Inc., and Tarpon Energy Services Ltd. Mr. Roane retired from TD Asset Management Inc., a subsidiary of The Toronto-Dominion Bank in Previously he was a founding partner of Lancaster Financial Inc., a financial advisory and investment management firm and was formerly employed by Burns Fry Limited and by the Toronto Dominion Bank. Mr. Roane holds a Bachelor of Arts (1977) and an MBA (1979) from Queen's University in Kingston, Ontario and holds the ICD.D designation from the Institute of Corporate Directors. Sheldon B. Steeves, Director (5)(8) Mr. Steeves has over 37 years of experience in the North American oil and gas industry and is currently a Director of Tamarack Valley Energy Ltd., a Canadian oil and gas company with operations in the Western Canadian sedimentary basin. From January 2001 until April 2012, Mr. Steeves was Chairman and CEO of Echoex Ltd., a junior private company focused on greenfield organic growth in Western Canada. Mr. Steeves spent over 15 years at Renaissance Energy where he was appointed Chief Operating Officer in He holds a Bachelor of Science in Geology from the University of Calgary. (1) Chairman of the Board (2) Ex-Officio member of all Committees of the Board (3) Member of the Corporate Governance & Nominating Committee (4) Chair of the Corporate Governance & Nominating Committee (5) Member of the Audit & Risk Management Committee (6) Chair of the Audit & Risk Management Committee (7) Member of the Reserves Committee (8) Chair of the Reserves Committee (9) Member of the Compensation & Human Resources Committee (10) Chair of the Compensation & Human Resources Committee (11) Member of the Safety & Social Responsibility Committee (12) Chair of the Safety & Social Responsibility Committee