The Game PlanU.S. BakkenDana W. Johnson, President, U.S. OperationsU.S. BakkenRegional Overview1Source: RSEG, Oct. 2010Enerplus landEnerplus land2Bakken & Three Forks GeologyMiddle Bakken Upper Three ForksGeological AgeMississippian DevonianDepth10,500 – 11,000 ft 10,600 – 11,000 ftThickness35 – 45 ft 30- 45 ftPorosity5 - 6% 6 - 10%Overpressure0.6 – 0.8 psi/ft 0.6 – 0.8 psi/ftOOIP/640 acres4 - 6 MMbbl 4 - 5 MMbbl• Believe all our acreage is prospective fordual development• Industry testing Three Forks proximal to ourleasehold:• Helis Oil and Gas Dodge 4-6-7 HR wellproduced 90 Mbbls in 4 months;offsetting our Fort Berthold acreage tothe west• KOG 14-21-33-16H3; 24 hour rate IP:1,042 BOE/d; 30 day average: 603BOE/day - only 6 of 22 stages currentlycompletedSource: Tudor Pickering Holt & Co.Fort Berthold Reserves vs. Contingent Resource• 22.4 MMBOE P+P reserves• 24 booked drilling locations• Less than 1 year’s drillinglocations• 60 MMBOE of “best estimate”contingent resource from theBakken only• 90 future drilling locations• 65% long laterals• 85% land utilization• ~15% recovery factor• Incremental upside from theThree Forks and downspacing3Almost 3x P+Preserve upside4Fort Berthold, North Dakota• Bakken & Three Forks potential• Long lease tenure, concentratedacreage position• 42°API, light sweet crude oil• High netback production ~$50/bbl• Production growth to over 20,000BOE/day over next 4 yearsKey FactsNet Acreage74,500 (116 sections)Current Production~4,000 BOE/dayP+P Reserves (Dec. 31, 2010)22.4 million BOEContingent Resource Est. (Best)60 million BOE>90% operated & ~90% working interest5Recoveries Improving Over Time6-10STAGES6-7STAGES10-24STAGESPeak *4 WellsAve. $6.1MM/WellImproving recoveries at Fort Berthold dueto longer laterals, more frac stages andbetter completionsPeak *5 WellsAve. $5.5MM/WellERF8 WellsAve. $6.9MM/Well* Peak Oil & GasFort Berthold Bakken Results to DateLong Laterals(9,000 ft. 24 frac stages)Short Laterals(4,500 ft. 12 frac stages)TypeCurveActual4 Well avgTypeCurveActual5 Well avgAverage 30 day initialproduction (bbls/day)1,100 – 1,200 1,250 550 – 650 730Expected Ultimate Recovery (Mbbls)600 – 800 300 – 400Cost/Well ($/MM)$8.5 $8.5 $6.0 $6.0120 day Cumulative Production (bbls)81,000 100,000 40,000 59,000Expected Net Present Value (12%, $MM)*$11.2 - $18.0 $3.9 – $7.4Expected Netback* ($/bbl)~$50 ~$50Expected Payout Period (years)0.8 – 1.3 1.3 – 2.2Expected F&D ($/BOE)$9.75 - $13.00 $13.50 - $18.506*Based on February 14, 2011 forward price•Royalties average 20%, plus state production tax of 11.5%, opcosts of $4/bbl, Differentialassumption of $10 - $12/bbl7Fort Berthold ResultsLong laterals are 35% ahead of the average type well predictionShort laterals are 45% ahead ofthe average type well prediction8• Typical rigs are 1,000– 1,600 hp with top drive toimprove performance; 2 of 4 drilling rigs in fleet areself moving (“walkers”)• Measured depth of wells are ~20,000’ (TVD 10,700’)and drill in approximately 28 days• Intermediate casing of 7” to the lateral• Liner 4.5” with swellable or mechanical external packersfor isolations and mechanical sleeves for stimulation• Frac design is 24 stages with ~125,000 lbs of highstrength proppant per stage to retain long-termconductivity and improve reserve recovery per wellEnerplus Well Design MethodologySource: Baker ToolsFort Berthold Well Costs9Completions- 125,000 lbs of proppant/stage, $1.3 - $1.5 MM for ceramic proppant- Water: 2,500 – 3,000 bbls/stage, $3 - 6/bbl for trucking & disposal feesTie-in- Additional $500,000Expect pad drilling will materially decrease tie-in costsTotal Cost $8.5 MM Total Cost $5.7 MM10Current Development PlansB BTFTFTFBBTF1320’1320’ 1320’1280 acres1280 acres• Maximize long horizontals• Develop from pads: 2 Bakken/2 Three Forks• Tie in as soon as possible• Test inter-well spacing• Work with other operators to time development• Reduce cycle time to 45 days from rig releaseof final well on pad to production• Implement salt water disposal solution• Understand and successfully implementsimultaneous operations• Drilling and completion of additional wellson producing padsWell TimelineWell application / permitapprovalSite BuildDrillingWaiting on FracCrewsFracing114-6 months• Environmental assessmentrequired on all federal lands• Have 11 permits in hand or verylate stage approval• Completing EA process onadditional 30 permits - expectapproval between April and June• 50 permits are underway forsubmittal between now andAugust• Expect 40 additional permitssubmitted by year-end1 month• Cannot beginbuilding siteuntil permit inhand1 month /well• Multi-wellpads• “walking rig”will helpreduce drillingtime2 months• Shortage ofbasin-widefleetsrelative todrillingactivity1-2 weeks10 – 12 months122011 Fort Berthold Bakken Plans• 2011 capital program - $230 million• 32 net operated wells, 75% long horizontals• Targeting Bakken primarily; 3 to 8 Three Forks wellsplanned• 3 to 4 rigs working in the play• Recently entered into agreements to secure fracservices, proppant and a rig to help ensure timelyexecution of plans• Expect to have midstream service agreements in place inmid-2011 to capture associated gas and liquidsProductiongrows from4,000 bbls/day to+20,000 BOE/dayover next 4 years13Execution Capability• 4 rigs under contract• 2 active at present; 2 moving inMarch / April, conditions permitting• Upgrading process• 2 “walkers” focused on pad drilling• Expect to sign at least oneincremental rig by September• Frac services:• Multi-year frac services agreementsigned – should keep pace with 3 –4 rig program• Plan to drill 40 – 50 wells/year from2012 – 2016 to fully develop acreage(Bakken and Three Forks)14Fort Berthold Production - Gathering• Enerplus has committed to a field gathering system at the Fort BertholdReservation which will:• Aggregate production at a central collectionpoint off the Reservation that willprovide flexible options for marketing the barrels• Gather and monetize both gas andliquids at market prices• Reduce the potential for shut in production due to varying weather, roadconditions, and availability of trucking contractors• Provide some ability to better manage and dispose of produced water• Reduce the number of trucks moving on the Reservation which will reducedust and road wear, and increasesafety for the residents15U.S. Bakken Infrastructure Capacity• Current U.S. Bakkenproduction is ~400MBOE/day• 500 MBOE/day in 2011• Pipeline capacity shortfall:• 80 MBOE/day in 2010• could increase to 125MBOE/day in 2011• Rail and trucking coverscapacity shortfall0100,000200,000300,000400,000500,000600,000700,000800,0002007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Mandan RefineryButte PipelineEnbridge North DakotaBelle Fourche ProposalKeystone XL Market LinkPlains Bakken ProposalEnbridge Bakken55k150k186k93k60k100k50k80k125kPipeCapacityShortfallSource: Internal company data and industry analysis• Numerous new pipelines and expansionsof over 300 MBOE/day are proposed toaddress the takeaway shortfall• We control some pipeline capacity and also sell to intermediaries who hold capacity onexisting pipelines or who have access to trucking/railing facilities

Barrels16Fort Berthold Production – Enerplus Regional Transportation05101520252011 2012 2013 2014

'000 bbls / day3rd Party Sales / TransportEnbridge Bakken ExpansionBelle Fourche ReversalFour Bears PipelineHistoric Enbridge CapacityBasic 4 Rig ProgramMiddle Pace (6 Rigs)Current Transportation / Sales Arrangements in Place forFort Berthold DevelopmentEnerplus has the flexibility to use its Enbridge North Dakota Pipeline capacity for itsSleeping Giant (Elm Coulee) production as well.2011 2012 2013 20142520151050

‘000 bbls/day17Sleeping Giant OverviewKey FactsNet Acreage~45,000 acresCurrent Production~7,800 BOE/dayP+P Reserves (Dec. 31, 2010)33.1 million BOE2011 Capital Plans$22.4 million4 net wellsEnerplus Acreage2011 planned wellsExisting wells• Acquired in 2005• Producing 42°light sweet crudefrom the Middle Bakken formation• Mature, cash generating asset• nearly fully developed to 3wells/section• limited remaining infilllocations• 2011 expected op costs of~$3.50/BOE and netback of over$50/BOE18Sleeping Giant – Technology Enhancing Results0501001502002503003504000 30 60 90 120 150

Normalized BOE/dayDaysNormalized Type Well Performance (3rd Wells per Section) @ Sleeping GiantAverage Type Performance - New Style Completions - Multi-Stage FracAverageType Performance - Old Style CompletionsNew completionsimprove recovery19U.S. Bakken Summary• Strategic asset for Enerplus for near-term growth and cash flow• Economics are best in our portfolio• Execution capability is critical• Three Forks potential• Managing the challenges while growing our operations