Peters & Co. Limited 2014 Energy Conference. September 10, 2014 ERF TSX & NYSE

Transcription

1 Peters & Co. Limited 2014 Energy Conference September 10, 2014 ERF TSX & NYSE

2 Enerplus Proven Strategy Focused, top tier resource plays & mature assets with low decline Disciplined, return-based capital allocation Deliver sustainable, profitable growth and income to investors Strong financial flexibility Competitive total return of 10%-15% 1

3 BOE Per Thousand Shares $ Per Share Demonstrated Per Share Growth Production/share Funds Flow/share $3.29 $3.76 $ E* E** * Based on mid-point of revised 2014 production guidance of 102,000 BOE/day and average shares outstanding. ** Analyst consensus at August 13,

4 Sustainable Growth & Dividend Strong funds flow growth supporting sustainable dividend E Funds Flow (MM) $645 $754 $879 (1) Capital Expenditures (MM) $853 $681 $800 Net Acquisitions & Divestitures (MM) ($91) ($120) ($104) (2) Dividends (MM) $302 $217 $220 SDP Proceeds (MM) ($43) ($46) ($20) Adjusted Payout Ratio (APO) (3) 174% 114% 115% (1) APO, net of A&D and SDP 158% 97% 102% D/FF ratio 1.7x 1.4x 1.3x (2) 1) Analyst consensus at August 13, ) At June 30, ) Adjusted payout ratio is calculated as the sum of dividends paid to shareholders plus capital expenditures divided by funds flow. 3

5 Q Results Increased Production Guidance and Lower Costs Production guidance increased by 4% 100, ,000 BOE/day Capital spending on track $800 MM Operating costs & G&A cost guidance reduced Op costs decreased by 1.5% to $10.10/BOE Cash G&A non-equity costs decreased by 6% to $2.30/BOE 4

6 Core Areas 2014E Production by Core Area U.S. Oil Williston Basin U.S. Natural Gas 30% Cdn Oil 20% U.S. Oil 25% Non-Core 10% Cdn Natural Gas 15% 2014 Capital 40% 2014 Capital 20% Operated Bakken/Three Forks position with 330 net future drilling locations Upside potential if higher recovery factor, additional Three Forks and EOR 25% of 2014E production (light crude) U.S. Natural Gas Marcellus Top tier dry gas play with robust economics and 240 net future drilling locations 30% of 2014E production Canadian Oil 2014 Capital 25% Canadian Oil Waterfloods Large OOIP with low decline 160 net future drilling locations and EOR potential 20% of 2014E production Natural Gas 57% Canadian Gas 2014E Production Mix NGLs 3% Crude Oil 40% U.S. Oil 2014 Capital 15% Canadian Natural Gas Deep Basin 160,000 net acres in the deep basin; 145,000 net acres are in the Wilrich and Duvernay with 450 net future drilling locations 15% of 2014E production PA U.S. Gas U.S. Gas 5

7 U.S. Core Oil: Fort Berthold, North Dakota Key Facts OOIP OOIP (W.I.) Net Acreage 2P Reserves at Dec 31, 2013 Best Estimate Contingent Resource 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 Q Production Net Locations Drilled to Date 330 wells 20,800 BOE/day 118 wells (90 Bakken/28 Three Forks) 2014 Focus: Down spacing tests Delineate Lower Three Forks Completion optimization/cost management 6

8 $Million CAD BOE/Day Fort Berthold Future Growth Potential FTB NOI* and Prod ,000 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 - Base NOI Base Capital Base Production 3-Rig Production 4-Rig Production * Assumes flat WTI of US$95.00 and Nymex of US$4.00 7

9 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 resource locations. 8

10 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 1 st Year Cum Prod (bbls) 155,000 98, , ,000 NPV 10% ($MM) $14.7 $4.7 $17.9 $7.4 IRR Btax (%) 60% 25% 130% 45% Payout (Yrs) Recycle Ratio Capital ($MM) * Assumes US$95/bbl WTI flat crude oil price and US$4.00/Mcf NYMEX natural gas price; based on long Bakken horizontal wells. 9

11 Peak Calendar Month Cumulative Production* (bbls) Fort Berthold Completions Enhancements Leading to Best in Basin Well Results 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 ~6,400 wells, at July 25,

12 Thickness U.S. Core Gas: Marcellus Enerplus Land Marcellus Well Key Facts Net Acreage 2P Reserves Dec 31, 2013 Best Estimate Contingent Resource Dec 31, 2013 Future Net Drilling Locations Q Production 57,500 acres 601 Bcf 1,340 Bcf 240 wells 189 MMcf/day 28% W.I. Concentrated, non-op position in NE Pennsylvania Marcellus production represents 56% of corporate natural gas volumes 70% of core acreage held by production 11

13 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, $MM EUR EUR EUR EUR US$ 4.00/Mmbtu 8 Bcf 12 Bcf 13 Bcf 16 Bcf IP30, Mmcf/d IRR, % PV10, $MM Capital, $MM The 13 BCF EUR case reflects infrastructure constrained production, with lower IP30 12

14 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 Source: ERF estimates (as of Aug 2014) Could see basis relief by 2017/2018 as capacity additions appear to be sufficient to meet this pace of production growth Growth in excess of takeaway capacity additions will further weaken NE Marcellus basis 13

15 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 14

16 Our Competitive Advantage Focused portfolio in top tier resource plays: Bakken/Three Forks, Marcellus, Deep Basin & Waterfloods Continued focus on capital discipline delivering 14% production growth in 2014 with a target capital efficiency of <$30,000/BOE/day Low corporate decline rate of 25% 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,

17 Supplemental Information

18 2014 Focus Operational execution Financial discipline Cost Reductions Expected production growth of ~14% Target capital efficiencies of <$30,000/BOE/day Adjusted payout and debt-to-funds flow ratios maintained or improved year-over-year Operating costs and general & administrative expenses Advance future opportunity set within portfolio Increased future opportunity at Fort Berthold Duvernay appraisal Commerciality of polymer project at Medicine Hat 17

19 Significant Future Drilling Inventory to Support Growth ~830 Future Drilling Locations Marcellus 240 Core Waterfloods 160 Deep Basin 100 Fort Berthold 330 * Based on 2P reserves and contingent resource locations at December 31, 2013 and as at June 1, 2014 for Fort Berthold. 18

20 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 100, ,000 BOE/day. ** Proved plus probable company interest reserves at December

21 $/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). 20

22 Funds Flow Protection WTI Crude Oil Hedges* Natural Gas Hedge Positions* Rest of 2014 Rest of % 50% 11% AECO Swaps $4.25/Mcf US$95.42/bbl 11% NYMEX Collars US$ $5.08/Mcf 68% 28% NYMEX Swaps US$4.14/Mcf ** 12% C$ % 77% 2015 US$93.68/bbl 20% NYMEX Swaps US$4.27/Mcf 38% 3% Q1 NYMEX Collars US$ $5.53/Mcf * As of July 23, 2014, based on weighted average price (before premiums), expected mid-point annual average production of 102,000 BOE/day, less royalties of 23%. ** Includes 9% (25 MMcf/day) protected at $4.17/Mcf with upside participation to $5.00/Mcf. 21

23 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

24 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% to +22,000 BOE/day Generated ~$44 million of free cash flow* 2014 YTD 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. 23

25 Fort Berthold: 250% Increase in Contingent Resource Original Assumption 2014 Evaluation Increase 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 OOIP 1 billion bbls 1.5 billion bbls 500 MMbbls 2P Dec. 31, MMBOE 105 MMBOE - Contingent Resource 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). 24

26 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. 25

27 Fort Berthold: Increasing to Average 7 Wells/DSU Enerplus Hognose Successful TF2 Enerplus Butterflies TF2 Drilling 8 Northwest Highest estimate of OOIP Includes TF2 8 well density 6,7,8 Central/West Well density ranging from 6 8 wells depending upon OOIP and TF2 prospectivity Industry TF2/TF3 Planned 6 or 7 Central/South Planned for 6 or 7 well density depending upon OOIP and recovery factor 26

28 Cum. Oil (Mbbls) Fort Berthold: Encouraging Enerplus High Density Tests Snakes Pad 8 Well Density & TF Snakes Pad Fur Bearers pad 7 Well Density 120 Fur Bearers Pad 40 TF1 Enerplus down spacing test (7 well density) Enerplus down spacing test & TF2 test Bakken Three Forks Drilling/ WOC 2 6 Months on Production 8 27

29 Cum Oil (Mbbls) per 1000 Lateral Feet Improving Productivity through Completion Enhancements Months 28

30 Oil (Mbbls) US$K Fort Berthold Completion Evolution Increasing Production Rates $350 $300 $250 $200 $150 $100 $50 $317 Completion Costs/Stage $240 $213 $195 $220 Despite larger fracs, the switch to sand and effective cost management has helped reduce completion costs $- BKN TF 30 Day Cum. Oil Significant increase in 30 day cumulative production from high intensity fracs 29

31 Capital Efficiency* (US$/BOE/day) Fort Berthold: Improving Capital Efficiencies* $15,000 $10,000 $12,000 $10,000 $8,500 $7,000 $6,000 Reduction in well costs and significant increase in IP rates driving top quartile capital efficiencies $5,000 $ 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) White Sand: Stages (~1000 lbs/ft) On-going focus on completion evolution and cost improvement * Capital efficiency based upon 30 day initial production rates 30

32 Fort Berthold U.S. Crude Marketing Total Industry Bakken Production Take-Away Capacity: Pipe 32% Available Capacity Rail 68% ~550,000 bbls/day of regional pipe capacity currently available and another 400, ,000 bbls/day coming into service after 2015 Rail loading capacity is plentiful with > 1.2 MMbbls available at more than 16 unit train facilities 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 for 2016 to Clearbrook * Refers to May 2014 North Dakota and Montana production of ~1.1 MMbbls per NDIC and Montana Board of Oil and Gas Conservation reports. 31

33 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 US$/Mcf Fort Berthold: Natural Gas and NGL Production 1,441 Fort Berthold (Q BOE/day) 1,136 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 Realized Gas Price Ft. Berthold (1300 BTU factor) 18,213 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 32

34 Low Decline Canadian Waterflood Assets Key Facts 28% 19% 6% 6% 2014E Production 3% 19% 10% 9% OOIP (W.I.) 1.3 billion bbls Recovery Factor to Date 24% 2P Reserves at Dec 31, 2013 Best Estimate Contingent Resource Dec 31, 2013 Future Net Drilling Locations Q Production 87 MMBOE 59 MMbbls EOR & IOR 160 wells 20,100 BOE/day Average decline rate 14% (SPARKY/LLOYDMINSTER) Core area representing almost half of corporate liquids production Lower growth profile with low decline Primary, secondary and tertiary oil recovery opportunities ~ 95% W.I. 33

35 $ Million Free Cash Flow from Waterflood Assets $350 $300 $250 $200 $150 $100 $50 NOI: $266 $124 NOI: $287 $137 53% 52% NOI: $301 $179 41% NOI: $320 $172 $132 46% NOI: $329 60% Significant free cash flow generation with reinvestment typically around 55% annually 2014 capital higher with Brooks program $ E* Capital Free Cash Flow * Based on July 24, 2014 forward curve and 2014 corporate differential assumptions. Free cash flow is calculated as NOI less capital expenditures; adjusted for acquisitions and divestitures. 34

36 MMcf/day Bcf of Natural Gas Marcellus Delivering Growth 200 Annual Production Reserves 2P: E Marcellus production continues to exceed expectations >90% production increase year-over-year 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 37 net future drilling locations P F&D of $0.58/Mcf & FD&A of $0.91/Mcf 1P:

37 Marcellus Sales Price Mix Q Dominion South: 35% TGP Z4 300 Spot: 30% Transco Leidy Spot: 26% Transco Z6 NNY: 3% 60% of Q2 production delivered on Transco, 40% on TGP, however, sales mix paints a different picture Regional firm, must-take contracts of ~70 MMcf/day plus 10 MMcf/day of pipeline capacity out of the region held in Q2 2014, with remainder sold at spot price. Remainder priced at: TETCO M3 (NY), TGP 500 (Tennessee) and TGP Z4 200 (Ohio) Lowered 2014 basis forecast to US$1.35/Mcf below NYMEX due to incremental production receiving weaker spot market pricing relative to our fixed volume term contracts * Map Source: Kinder Morgan. 36

38 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 Q 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 * NE is defined to include Dominion, Millennium, TGP and Transco pipelines. 37

39 Canadian Gas Deep Basin (Wilrich) Contiguous land blocks in highly prospective regions Edson smaller acreage position - Infrastructure available - Significant competitor activity Ansell most developed - Infrastructure in place - Seismic available Minehead - 3D seismic acquired Hanlan - Earliest stage of development - Very little drilling to date Key Facts Key properties Net Acreage (acres) 2P Reserves Dec 31, 2013 Best Estimate Contingent Resource Dec 31, 2013 Future Net Hz Drilling Locations Est. EUR/Well Q Stacked Mannville Production Growth potential to 60+ MMcf/day Edson, Ansell, Minehead, Hanlan 60,000 acres (92 sections, majority 100% WI) 62 Bcfe 253 Bcfe >100 wells Bcfe 29 MMcf/day Ownership in existing infrastructure to support up to 50 MMcf/day 38

40 Wilrich Activity Plan to continue to develop Tier 1 lands in the near-term Results have varied across the play with the most prospective wells to date coming from the Ansell/Minehead area AECO $4.00/Mcf EUR 7 Bcf EUR 6 Bcf EUR 5 Bcf NPV10 ($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 Delineation of Tier 2 & 3 lands will be dictated by economics AECO $3.50/Mcf NPV10 ($MM) $5.2 $4.0 $2.7 IRR (%) Payout (years) Assumptions: Capital: $7MM/well; assumes pad drilling Liquids: 7-10 bbls/mmcf 39

41 Duvernay Shale Willesden Green R12W5 R11W5 R10W5 R9W5 R8W5 R7W5 R6W5 R5W5 R4W5 R3W5 ENERPLUS HZ W5M Logged & cored Vt pilot. Hz well, Rig Released 02/27/2014 ENERPLUS W5M Rig Released: 10/23/2013 Vertical Cored, Prepped for Re-entry ENERPLUS W5M Rig Released: 10/26/2012 Vertical Cored ENERPLUS W5M Rig Released: 8/30/2013 Vertical Cored ENERPLUS HZ W5M Horizontal Re-entry On production 06/ ,000 net acre (100% W.I.) land position built over past 3 years at <$750/acre Increased industry activity in Willesden Green region providing additional geological and reservoir control Future development at 3-4 wells per section provides Hz potential drilling locations Core analysis from 4 vertical tests supports a range of free condensate yields across a significant portion of acreage Producing Wells Drilled Wells Licensed Wells Completed 2 Hz wells to-date in W5M on stream June W5M on stream early fall 2014 R12W5 R11W5 R10W5 R9W5 R8W5 R7W5 R6W5 R5W5 R4W5 R3W5 40

42 Production Composition 2014E Production 2014E Crude Oil Composition U.S. Gas 33% U.S. Liquids 25% Canada Heavy 22% Canada Gas 24% Canada Liquids 18% Canada Medium 11% Canada Light 9% U.S. Light 58% 2014 Differential/Basis Outlook*: Mixed Sweet Blend (MSW) ($7.00)/bbl Western Canada Select (WCS) ($25.00)/bbl U.S. Bakken (at inlet to pipe/rail)** (US$10.00)/bbl Marcellus Basis (US$1.35)/Mcf *The differential/basis outlook includes the impact of Enerplus marketing and transportation arrangements. ** It costs an average of $3.00/bbl to transport production from the field to market sales points, resulting in an expected field differential of $13.00/bbl below WTI. 41

43 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 $12.9 $0.06 Change of $0.50/Mcf NYMEX natural gas $21.3 $0.10 Change of 1,000 BOE/day production for rest of year $ 5.0 $0.02 Change of $0.01 in the US$/CDN$ exchange rate $ 4.6 $0.02 * The sensitivities above reflect our forecasts, outstanding commodity contracts, approximately million outstanding shares, and are based on forward markets as at July 24,

44 Debt Composition* Unused Capacity* $921MM Senior Notes* US$862MM 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, 2016 Credit Facility* $79MM Senior Unsecured Notes* - CDN$990 MM Notes are rated NAIC 2 and rank equally with bank credit facility; average interest rate of 5.3% US$200 million private placement of senior unsecured notes with a 10 year average life and interest rate of 3.79% * Debt composition at June 30, 2014 has been adjusted to include the senior notes offering, which closed on September 3, Canadian dollar equivalent of U.S. dollar denominated notes FX rate at June 30, 2014 US/CDN of

45 $ Millions Senior Notes Maturities* Average interest rate of 5.3%* $900 $800 $836 $700 $600 $500 $400 $300 $200 $100 $0 $94 $12 $ * Outstanding senior notes maturities as at June 30, 2014, adjusted for the US$200 million senior notes offering, which closed on September 3, US$ amounts converted at US/CDN

46 Enerplus Share Ownership Investor Composition Geographic Composition Total Retail 58% Total Institutional 42% 25% 41% 42% 17% 58% 17% US & Other Retail Canadian Retail US & Other Institutional Canadian Institutional United States & Other Canada As of July 18,

47 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.

48 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). Douglas R. Martin, Director Mr. Martin is President of Charles Avenue Capital Corp., a private merchant banking company, since April From 1993 until 2000, Mr. Martin was Chairman and Chief Financial Officer of Pursuit Resources Corp., a public oil and gas corporation that was acquired by EnerMark Income Fund (a predecessor of Enerplus) in April From 1972 until 1993, Mr. Martin held positions of increasing importance with N.M. Davis Corp., Dome Petroleum Ltd. and Interhome Energy Inc. (now Enbridge Inc.), and was the Senior Vice President and Chief Financial Officer of Coho Energy Inc. from 1989 until Mr. Martin graduated from the University of Toronto in 1966 with a B.A. in Political Science, and received his Chartered Accountant designation from the Ontario Institute of Chartered Accountants in He also graduated with Honours from York University in 1972 with an MBA in Finance.

49 Enerplus Board of Directors continued 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. 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

50 Forward Looking Information Advisory 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, this presentation contains forwardlooking information pertaining to the following: Enerplus' asset portfolio; future capital and development expenditures and the allocation thereof among our assets; future development and drilling locations, plans and costs; the performance of and future results from Enerplus' assets and operations, including anticipated production levels, expected ultimate recoveries 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; future funds flow and debt-to-funds flow levels; potential asset acquisitions and dispositions; rates of return on Enerplus' capital program; Enerplus' tax position; sources of funding of Enerplus capital program; 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, cash flow and other sources 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 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 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 our AIF and Form 40-F described above). The purpose of certain financial outlook information included in this presentation, including with respect to our 2014 guidance for funds flow, is to communicate our current expectations as to our performance in Readers are cautioned that it may not be appropriate for other purposes. 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 them to reflect new events or circumstances, except as may be required pursuant to applicable laws. Assumptions All amounts are stated in Canadian dollars unless otherwise specified. 49

51 Advisories 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. 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. 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. 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 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, 2013, which will include 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. 50

52 Advisories 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 estimate of contingent resources included in this presentation were evaluated by Enerplus and audited by independent reserve evaluators, McDaniel & Associates. "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 resource 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 resource estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered, effective as of June 1, 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 Fort Berthold 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 See "Non-GAAP Measures" above. 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 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. 51

53 Advisories 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. 52

54 Investor Relations Contacts Jo-Anne M. Caza Vice-President, Corporate & Investor Relations The Dome Tower Suite 3000, 333 7th Ave SW Calgary, AB Canada T2P 2Z1 53