The Game Plan

Investor Update

May 2012

• Own a portfolio of oil and gas resource plays in North America which

includes:

• early stage assets that offer scope and scale as well as future option value

• producing assets with development opportunity

• Improve the profitability of our assets and continue to demonstrate our

execution capability

• Delineate prospective resource and strategically monetize a portion to

facilitate our growth and income model

• Pursue strategic acquisitions complementary to the existing portfolio

• Maintain a healthy balance sheet

• Committed to yield

Corporate Strategy

1

Dividends/Distributions - a Key Component of Shareholder Return

2

$0.00

$1.75

$2.72

$3.32

$5.65

$3.29

$2.83

$3.68

$2.60 $2.58

$3.97

$4.52

$3.12 $3.32

$5.26

$5.61

$3.25

$4.29 $4.20

$4.47

$5.04 $5.04 $4.89

$2.16 $2.16 $2.16

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

198

6

198

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198

8

198

9

199

0

199

1

199

2

199

3

199

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199

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199

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199

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199

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199

9

200

0

200

1

200

2

200

3

200

4

200

5

200

6

200

7

200

8

200

9

201

0

201

1

CD

N $

’000s

Cumulative dividends paid Cash dividends / distributions per share

$91.89/share paid since

inception*

* As of December 31, 2011

Paid over $6 billion in

cumulative dividends*

Delivering Organic Production Growth

3

• Oil and liquids production

growing to 50% of total in 2012

• oil production growth of 22%

• natural gas production flat

• Production growth

concentrated in:

• Tight Oil ~45% growth with

netback of ~$50/BOE

• Waterfloods ~ 3% growth with

netback of ~$48/BOE

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2010 Exit 2011 AA 2011 Exit 2012 AA 2012 Exit

BO

E/d

ay

Oil Gas

175% Organic Reserve Replacement in 2011

4

53% 57%

47% 43%

0

50

100

150

200

250

300

350

20102P Reserves*

20112P Reserves*

MM

BO

E

Crude Oil and Liquids Natural Gas

306 MMBOE 322 MMBOE

• 2P reserves increased by 5%

• Replaced 300% of our oil

production, growing 2P oil

reserves by 14%

• NPV of reserves increased by

10% in 2011 due to increased

weighting of oil in portfolio

• NPV of Fort Berthold oil

property up 160% due to

success of drilling program

* Company interest reserves

Competitive Finding & Development Costs

(1) Proved + probable reserves at December 31, 2011 including future development capital

5

$26.26 $26.59

$22.68

$0

$5

$10

$15

$20

$25

$30

Enerplus Oil weightedpeers

All peers

$/B

OE

F&D Cost/BOE(1)

$17.89

$23.84

$20.32

$0

$5

$10

$15

$20

$25

Enerplus Oil weightedpeers

All peers

$/B

OE

FD&A Cost/BOE(1)

Oil weighted peers includes: Baytex, Crescent Point, PennWest, Petro Bakken

All peers includes above as well as: ARC, Bonavista, NAL, Pengrowth, Progress, Vermillion

75% Oil* 83% Oil*

61% Oil*

* % of 2P reserve additions attributable to crude oil

Significant Upside Potential

• Contingent resources are

1.5x 2P reserves

• 485 future drilling

locations associated with

contingent resources

• Over 100 oil locations

• Further unassessed

resource potential in

waterfloods, liquids rich

natural gas and North

Dakota tight oil

* Best estimate of contingent resources assessed both internally and externally at Dec 31, 2010 and Dec 31, 2011 6

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

2010Contingent Resources*

2011Contingent Resources*

Tcfe

Natural Gas

Marcellus

0

25

50

75

100

125

150

2010Contingent Resources*

2011Contingent Resources*

MM

BO

E

Crude Oil

Waterfloods Tight Oil

Sold

~1.6 Tcfe

Converted

~5

MMBOE

Added +19

MMBOE

Converted

~30

MMBOE

7

Opportunity Rich Portfolio

Cardium/other

new oil plays

30,000 net

acres

Stacked

Mannville

67,000

net acres

Duvernay

72,000

net acres

Montney

33,000 net

acres

Fort Berthold

Bakken/Three

Forks

74,000 net

acres

Marcellus

110,000

net acres

• Over 200 drilling locations

identified on our oil assets

• Significant additional

upside through increased

density, EOR and drilling

on undeveloped lands

• Over 575 drilling locations

identified on our natural gas

assets

• Over $10 billion of

potential investment on

undeveloped acreage

Waterfloods

14 properties

with IOR &

EOR

Preserving Financial Flexibility

8

• We currently have a strong balance sheet but low gas prices are creating funding

challenges (1.6x debt to funds flow at March 31, 2012)

• Actions taken to date include:

• February 8, 2012 equity issue - $330 million

• Stock Dividend Program - $70 million estimated proceeds in 2012

• extending credit capacity with term debt - $405 million

• We have plans to manage debt levels through a number of initiatives over the

next 18 months

• monetizing our equity portfolio

• joint venture or sale of a portion of undeveloped land

• $250 to $500 million in total

• Depending on the progress with respect to these funding initiatives and realized

commodity prices, there could be downward pressure on:

• capital spending and growth rates

• dividends

9

Implementing Stock Dividend Program (“SDP”)

• Benefits:

• All shareholders are now eligible to participate

• Shareholders can elect to receive cash dividends or Enerplus shares

• 5% discount to current market price and no fees or commissions

• Participation in the SDP is not expected to generate dividend income

for Canadian shareholders

• SDP participation is completely optional

• Replaces current DRIP

2012 Capital Program Delivers 10% Production Growth

• Total 2012 capital budget of $800 million delivers 10% growth in annual

average production

• 70% of capital directed toward oil and natural gas liquids projects

• No spending on Canadian shallow gas assets

• Marcellus focused on lease retention and limited delineation on operated leases

• $80 million directed toward delineation of new plays - Montney, Duvernay,

emerging oil plays and operated Marcellus acreage

8

2012 Capital Spending Breakdown 2012E

($ millions)

Tight Oil - $300 million at Fort Berthold $350

Waterfloods $150

Marcellus - $150 million non-operated/$40 million operated $190

Deep Basin – primarily Stacked Mannville $65

Our Operational Focus in 2012

• Execution at Fort Berthold

• Reduce cycle times on new wells

• Reduce downtime

• Test downspacing

• Continue to advance on our waterflood projects

• Advance EOR pilots at Giltedge & Med Hat

• Drilling/injector conversions to enhance efficiencies

• Delineate new resource plays in Canada

• Montney, Duvernay, emerging oil plays

• Spend to maintain Marcellus land position

• Continued focus on cost management

• Capital efficiencies

• Operating costs

11

Expected exit

capital efficiencies

of $30,000 -

$35,000/BOE/day

• Production averaged 79,200 BOE/day (+3% from Q4 2011)

– 47% oil and liquids, up from 44% in 2011

• Invested $317 million in development capital drilling 25 net wells with

14 net wells brought on-stream

– $138 million focused at Ft. Berthold

• Generated funds flow of $163 million ($0.86/share)

– unchanged vs Q4 2011 due to higher oil production offsetting weak

natural gas prices

• Debt to 12 trailing month funds flow ratio of 1.6x

• Operating costs and G&A in line with expectations at $10.00/BOE

and $3.51/BOE respectively

First Quarter Results Meeting Expectations

12

Fort Berthold Leads the Charge in Oil Growth

13

Key Facts

Net Acreage (acres) ~74,000 (115 sections)

2011 P+P Reserves 55.4 MMBOE

2011 Best Estimate

Contingent Resources

49 MMBOE

2011 Q4 Production

2012 Q1 Production

6,800 BOE/day

8,700 BOE/day

Current Operated and Non-Operated Locations

• Concentrated, top tier land position in North

Dakota

• Average 90% working interest

• 130+ future drilling locations; 32 horizontal

operated wells drilled to date

• Expected netback of $50 - $55/BOE in 2012

14

Fort Berthold Bakken Economics

Bakken Long Laterals

9,500 ft. 20 - 24 frac stages, $11 MM/well

Type Curve

30 Day IP 1,240 bbls/day

EUR:

Oil

Gas

NGLs

940 MBOE

800 Mbbls

470 MMcf

75 Mbbls

IRR 90%

Net Present Value (10%)* $17 million

Payout Period 1.2 years

Recycle Ratio 4.0x

* Economics are before tax in US dollars based on March 26, 2012 forward prices. Royalties average 19.5%, plus state production and

extraction tax of 8.5%

Fort Berthold Cost Mitigation & Field Optimization

15

• Improved drilling cycle times

• Best rig now averaging 30 days for long drill well versus 37 day average

• Completion design

• Testing different completion techniques

• Optimize stages, water, proppant

• Water management

• Full year of salt water disposal wells

• Reduction in completion costs

• Added second SWD well

• Evaluating piping system for SWD

• Continue infrastructure build out for well tie-ins

• 50% of wells tied-in now, 75% expected by year-end

• Production optimization

• Increase in service rigs to improve uptime – target 50% reduction in downtime

Canadian Waterflood Assets

Key Facts

OOIP ~1.6 billion barrels (net)

P+P Reserves (YE 2011) 90 million barrels net

(26% recovery)

Recovery to date 21%

Best Est. Contingent

Resources

56.3 million barrels

Average Oil Quality 30° API

2012E Annual Production 17,000 BOE/day

21% of total

16

IOR – Improved Oil Recovery (Secondary recovery)

EOR – Enhanced Oil Recovery (Tertiary recovery)

• Line of sight to grow production by ~5% per year through focused IOR/EOR

• 50% of net operating income reinvested to maintain production

• 2012 program in support of strategy

• Spend $150 million on ~40 horizontal high working interest operated oil wells and upgrading facilities

• Implement EOR projects

17

Defining the IOR/EOR Opportunity in Canada

Asset

OOIP

(net)

(MMBbl)

2011

YE 2P

Reserves

(MMBOE)

Total

Recovered

(MMBbl)

Contingent

Resource

(MMBbl)

Incremental

Recoverable

2011 Net

Operating

Income IOR EOR Total

Medicine Hat, AB 217 16.7 8% 5.5 21.7 27.2 13% $42.50/BOE

Giltedge, AB 126 11.0 14% 4.0 11.8 15.8 13% $44.00/BOE

Freda/Skinner

Lake/Neptune, SK

99 12.7 14% 7.2 0 7.2 7% ~$60.00/BOE

Cadogan, AB 45 2.4 9% 3.3 0 3.3 7% $54.00/BOE

Virden/Daly, MB 283 8.2 28% 2.8 0 2.8 1% ~$63.00/BOE

Sub-Total* 770 51.0 17% 22.8 33.5 56.3 7%

* There are other waterflood properties that contribute to reserves and production within this resource play that are not included above

• EOR potential also at

Freda/Skinner Lake/Neptune;

Virden/Daly

• ~340 net locations to unlock

potential value of our assets

• Incremental 5 -15% recovery

Further Upside Potential

Field

OOIP

(MMBbl)

2011

YE 2P

Reserves

(MMBOE)

Recovery

Factor for

Oil

Reserves

Total

Recovered

EOR/

IOR

Pembina 252 21.6 35% 28% Both

Gleneath 103 4.4 23% 19% Both

Joarcam 166 3.2 42% 40% Both

Brooks 193 12.5 34% 30% IOR

18 18

Marcellus: Retaining Leases for Future Value Capture

• 65,000 net operated acres with 90%

working interest

• ~$40 million in capital in 2012 focused on

delineation

• 45,000 net non-operated acres

with 20% avg. working interest

• Major non-op partners:

• EXCO (22% WI)

• Chief (18% WI)

• ~$150 million in capital in 2012

focused on lease retention and

reserve/production growth

• 110,000 net acres with ~450

future drilling locations to

support future reserve and

production growth

• Contingent resource

estimate of 2.3 Tcf – nearly

triple our 2P natural gas

reserves

• 2012E exit production: > 70

MMcf/day (+180%)

• 2012 Plans:

• $190 million in capital to

drill and bring on-stream

~20 net wells

Well Performance Continues to Exceed Expectations

19

0

500

1000

1500

2000

2500

3000

0 30 60 90 120 150 180 210 240 270 300 330 360

Cu

mu

lati

ve

Pro

du

cti

on

(M

Mc

fe)

Days Producing

Top 5 Wells

Average Actual Production

6.0 Bcfe Type Curve

3.5 Bcfe Type Curve

• Average EURs have

increased from 3.2 – 3.4

Bcf/well to 6.6 Bcf/ well

• Increased land utilization

from 55% to 65%

• High EUR estimate has

increased from 5 Bcf/well

in 2009 to an average of

11 Bcf/well today in

Susquehanna County

N.E. PA Well Performance

20

2012 Non-Operated Plans Focused on Lease Retention

• $150 million capital budget for 2012

• Rig count has dropped while maintaining the

minimum needed for lease obligations

• 19 net new drills planned in 2012, 18 on-streams

• ~50% of 2012 drilling planned in areas with water

and pipeline infrastructure already in place

• 90% of 2012 capital program targeted in locations

with anticipated EURs of 7-9 Bcf/well

• ~50% in 9 Bcf/well areas

EXCO Resources

Chief O&G & CHK

16

13 10

0

5

10

15

20

Sep-11 Jan-12 Current

Planned 2012 Rig Activity by Non-Op Partners on Enerplus Acreage

Partners are managing activity in current market conditions

21

• Approximately 170,000 net acres of

high working interest land

throughout the region

• Includes 100% working interest in

approximately 145,000 undeveloped

acres

• Multiple contiguous acreage blocks

• Potential of liquids rich zones

• 2012 capital focused on delineating

the resource given price

environment

• Duvernay – 2 vertical strat wells

• Montney - 1 vertical strat and 1 hz

• SM Wilrich – 2 hz producers

Montney Potential

• 33,000 net acres of

undeveloped land

Stacked Mannville

Potential

• 67,000 net acres of land

(42,000 undeveloped)

21

Large, long tenure, high working

interest land holdings

Defining the Gas Opportunity (Deep Gas)

Duvernay Potential

• 72,000 net acres of

undeveloped land

Outlook

• Good mix of early stage, high growth, and mature oil and gas properties

• Abundance of growth opportunities in our portfolio today – not reliant on

acquisitions

• We had a strong year in 2011 with respect to organic reserve replacement

through organic growth and F&D costs

• Oil weighting is increasing:

• 75% of 2011 reserve additions were from oil and liquids increasing overall to 57% of proved

plus probable

• Production share of oil and liquids ~50% by end of 2012

• 70% of capital spending directed towards oil & liquids

• We have a healthy balance sheet and plans to manage our debt levels in the context

of weak natural gas prices

• Objective is to deliver competitive total return comprised of sustainable growth and

income

22

The Game Plan Supplemental Information

24

17%

18%

48%

17%

US/Intl Institutional Canadan Institutional

US/Intl Retail Canada Retail

Enerplus Share Ownership

35%

63%

2%

Canada US Other

As of December 31, 2011 As of January 23, 2012

Investor Composition Geographic Composition

Total Retail

65%

Total Institutional

35%

25

Hedging

• 62% of net oil production hedged

at US$96.22/bbl

• Physical fixed price contracts in

place for 27% of net natural gas

production at CAD$2.17/Mcf –

April – October, 2012

42%

58%

Hedged Spot

62%

38%

Hedged Spot

2012 Crude Oil 2013 Crude Oil

• 42% of net oil production hedged

at US$103.00/bbl

• No natural gas hedges in place at

this time

* As of May 2012

26

Bakken Well Results Continue to Outperform

-

200

400

600

800

1,000

1,200

1,400

0

50

100

150

200

250

300

1 3 5 7 9 11 13 15 17 19 21D

aily P

rod

ucti

on

(b

bl/d

ay)

Cu

mu

lati

ve P

rod

ucti

on

(b

bls

)

Months

Bakken Long Well Performance

Cumulative Type Curve Actual Cumulative Average

Daily Production Type Curve Actual Daily Average

7 wells

5 wells

4 wells

3 wells

2 wells

1 well

0

100

200

300

400

500

600

700

-

20

40

60

80

100

120

140

160

180

1 3 5 7 9 11 13 15 17 19 21 23

Daily P

rod

ucti

on

(b

bl/d

ay)

Cu

mu

lati

ve P

rod

ucti

on

(b

bls

) Months

Bakken Short Well Performance

Cumulative Type Curve Actual Cumulative Average

Daily Production Type Curve Actual Daily Average

PLACEHOLDER ONLY:

NEED THE daily type curve

18 wells

11 wells

9 wells

5 wells

3 wells

2 wells

1 well

27

North Dakota Takeaway Capacity

• Rail and pipeline commitments in place for 8,500 bbls/day in 2012 and 14,000 bbls/day in 2013

• 2,000 to 3,000 bbls/day directly exposed to LLS pricing through Feb 2014

Non-Operated (~47,000 net acres in PA)

• Operated primarily by Chief, Exco and Chesapeake

• Anticipate 30% - 35% of leasehold to be held by production by end of 2012

• Approximately 22,000 net acres expire in 2013

• Expect majority to be either extended under pre-negotiated options or to be held by production via 2012-

2013 drilling activity results in ~70% of prospective acreage held by end of 2013

Operated (~68,000 net acres)

• Pennsylvania (~7,000 net acres)

• Majority of leases expire in 2015

• West Virginia/Maryland (~61,000 net acres)

• Expirations (acres):

• 2012: 28,000 acres - 95% of leasehold can be extended for $1.6MM

• 2013: 29,000 acres - 90% of leasehold can be extended for $15.8MM

• 2014+: 4,000 acres

Marcellus Lease Tenure

28

29

Stacked Mannville

• Acquiring and utilizing 3D seismic

• Drilled 5 Hz delineation wells to date, 3

others licensed and ready to execute

• Liquids ratios of 7 – 30 bbls/MMcf

• Additional de-risking ongoing by competitors

and partners

Key Facts

Key properties Pine Creek to Hanlan

Net Acreage (acres) ~67,000 total (42,000 undeveloped)

Future HZ Drilling

Locations

100 - 200

Expected EUR/Well 4.0 - 6.0 Bcfe

Enerplus working interest lands

Contiguous land blocks in highly

prospective regions

30

Wilrich Type Curve Economics

4.0 Bcf Well 6.0 Bcf Well

AECO

($/Mcf)

IRR

%

Payout

(Years)

NPV

10%

($MM)

IRR

%

Payout

(Years)

NPV

10%

($MM)

$4.00 30 2.7 3.6 67 1.6 8.6

$3.00 16 4.0 1.1 40 2.2 5.1

$2.00 2 9.5 -1.4 18 3.7 1.4

Capital* $7.1 million $7.1 million

30 Day

IP 3,800 Mcf/day 6,000 Mcf/day

Liquids 7 bbls/MMcf 7 bbls/MMcf

BESC $2.81/Mcf $1.61/Mcf

• Type curves are based on offset data

and are supported by our well results

• Positive drilling results to date:

• Horizontal drill - 13 MMcf/day (facility

constrained) peak rate production at

14 Mpa after 165 hours with 15,549

bbls of water recovered

• Produced at 10 MMcf/day for

first 30 days

• Second horizontal drill - 31 MMcf/day

(facility constrained) peak rate

production at 19 Mpa after 90 hours

with 6,900 bbls of water recovered

* Capital assumes pad drilling

31

Progress/Petronas

North Montney JV

(Lily)

Enerplus Julienne Creek Lands

North Montney Regional Pool

Progress Town

3D seismic outline

Painted Pony Blair

Montney Vert. Test Well

T North Sales Line

Montney – Cameron/Julienne Creek

• 3D seismic purchased and

reprocessed

• Existing well and vertical test well

indicate approximately 300 metres

of Montney thickness

• Rock analysis indicates good

reservoir development

• Enerplus vertical testing upper and

lower Montney:

• Drilled to 2,400 metres,

positive gas tests that

support type curve

Key Facts

Key Properties Cameron/Julienne Creek

Net Acreage ~33,000 acres (+50 sections)

Estimated OGIP 150 Bcf/section

Future Hz Drilling

Locations

350 - 400

Expected

EUR/Well

4.0 – 6.0 Bcfe

32

Upper Montney Type Curve Economics

4.0 Bcf Well 5.0 Bcf Well 6.0 Bcf Well

AECO

($/Mcf)

IRR

%

Payout

(Years)

NPV

10%

($MM)

IRR

%

Payout

(Years)

NPV

10%

($MM)

IRR

%

Payout

(Years)

NPV

10%

($MM)

$4.00 25 3.5 2.5 40 2.6 4.3 57 2.0 6.2

$3.00 15 5.3 0.8 25 3.7 2.4 35 2.8 4.0

$2.00 4 10.8 (1.2) 10 6.7 0.1 17 4.8 1.4

Capital $6.2 million $6.2 million $6.2 million

30 Day IP 4,000 Mcf/day 5,000 Mcf/day 6,000 Mcf/day

Liquids 10-15 bbls/MMcf 10-15 bbls/MMcf 10-15 bbls/MMcf

BESC $2.78/Mcf $1.99/Mcf $1.47/Mcf

• Type curves are based on wells in the North Montney trend (Town & Blair) and are supported by

our vertical Montney test well

• Capital assumes pad drilling

33

• Duvernay has analogous rock characteristics to the Eagleford

• Prolific over-pressured Devonian source rock

• Within the gas condensate window, based on:

• Offsetting well control and reported competitor activity

• Equivalent thermal maturity and depth to proven liquid-rich

Kaybob area

• Existing and newly announced mid-stream gas infrastructure,

including deep cut gas plants, provides numerous options for

product marketing

• 4 well/section development provides us with over 400

future Hz drilling locations

• Favorable royalty of 5% for first 5 years of production

Why the Duvernay Shale at Willesden Green?

110 sections in the

gas condensate

window with

net OGIP of

+7 Tcf

34

Duvernay Shale – Willesden Green

• Early stage liquids rich natural

gas play in central Alberta

• Over-pressured at ~56MPa

• Targeted type well:

• Hz well cost of ~$12 million

• 30 day IP of ~5 MMcf/day

• Liquids 75 - 100 bbls/MMcf

• Focus on early stage

evaluation in 2012

• 2 wells planned for Q3/Q4

Key Facts

Key Properties Willesden Green, AB

Net Acreage ~70,000 acres (110 sections)

Est. OGIP ~65 Bcf/section

Est. Density 4 wells/section

Expected

EUR/Well

3.5 Bcf

Bellatrix

Sinopec Daylight

Sirius

Antelope COP

COP ECA

Bonavista

ECA

ECA ECA

TLM

Enerplus Duvernay

Land sales (since Dec/2010)

Licenced Wells

Drilled/Drilling Wells

Duvernay Penetrations

Disclaimers

35

Assumptions

All economics contained have been calculated using forward prices and costs as of March 26, 2012. All amounts are stated in Canadian dollars unless otherwise specified.

Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent

This presentation contains references to "BOE" (barrels of oil equivalent), "Mcfe" (thousand cubic feet of gas equivalent), "Bcfe" (billion cubic feet of gas equivalent) and "Tcfe"

(trillion cubic feet of gas equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs,

and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Mcfes, Bcfes and Tcfes. BOEs, Mcfes, Bcfes and Tcfes may be misleading,

particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not

represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy

equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent",

respectively.

Presentation of Production and Reserves Information

In accordance with Canadian practice, production volumes and revenues are reported on a “Company interest” basis, before deduction of Crown and other royalties, plus

Enerplus’ royalty interest. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company interest reserves"

using forecast prices and costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators

("NI 51-101"), being Enerplus' working interest before deduction of any royalties), plus Enerplus' royalty interests in reserves. “Company interest reserves" are not a measure

defined in NI 51-101 and do not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or

disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2011, which include complete disclosure of our oil and gas reserves and other

oil and gas information in accordance with NI 51-101, are contained within our Annual Information Form for the year ended December 31, 2011 ("our AIF") which is available on

our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, the Annual Information Form is part of our Form 40-F that is filed with the U.S.

Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial

statements filed on SEDAR and EDGAR concurrently with this presentation for more complete disclosure on our operations.

Contingent Resource Estimates

This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources"

are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to be potentially

recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable

due to one or more contingencies. Contingencies may include factors such as ultimate recovery rates, economic, legal, environmental, political and regulatory matters or a lack of

markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associa ted with a project in the early evaluation stage.

Enerplus expects to develop these contingent resources in the coming years however it is too early in their development for these resources to be classified as reserves at this

time.

There is no certainty that we will produce any portion of the volumes currently classified as “contingent resources”. The “contingent resource” estimates contained herein are

presented as the "best estimate" of the quantity that will actually be recovered, effective as of December 31, 2011. A "best estimate" of contingent resources means that it is

equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabil istic methods are used, there should be at least a 50%

probability that the quantities actually recovered will equal or exceed the best estimate.

Disclaimers

36

For additional information regarding the primary contingencies which currently prevent the classification of our disclosed “contingent resources” associated with our Marcellus

shale gas assets, our North Dakota Bakken properties and our crude oil waterflood properties as reserves and the positive and negative factors relevant to the “contingent

resource” estimates, see our Annual Information Form for the year ended December 31, 2011 (and corresponding Form 40-F) dated March 9, 2012, a copy of which is available

under our SEDAR profile at www.sedar.com and a copy of the Form 40-F which is available under our EDGAR profile at www.sec.gov.

F&D and FD&A Costs

F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in

the year plus the change in estimated future development costs in the year, by the additions to proved reserves in the year, and (ii) in the case of F&D costs for proved plus

probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the

additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during

that year in estimated future development costs generally will not reflect total finding and development costs related to its reserves additions for that year.

FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the

cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves including net acquisitions in

the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred

in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves including net acquisitions in the year. The

aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally

will not reflect total finding, development and acquisition costs related to its reserves additions for that year.

Non-GAAP Measures

In this presentation, we use the terms “funds flow”, "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "F&D costs"

and “FD&A costs” as measures of operating performance. We calculate funds flow based on cash flow from operating activities before changes in non-cash operating working

capital and decommissioning expenditures, all of which are measures prescribed by Canadian generally accepted accounting principles (“GAAP”) which were revised effective

January 1, 2011 to converge with International Financial Reporting Standards (“IFRS”) and which appear in our Consolidated Statements of Cash Flows. We calculate "payout

ratio" by dividing dividends to shareholders by funds flow. "Adjusted payout ratio" is calculated as cash dividends to shareholders plus development capital and office

expenditures, divided by funds flow from operating activities.

Enerplus believes that, in addition to net earnings and other measures prescribed by GAAP, the terms “funds flow”, "payout ratio", "adjusted payout ratio", "F&D costs" and

“FD&A costs” are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are

not measures recognized by GAAP and do not have a standardized meaning prescribed by GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable

to similar measures presented by other issuers.

NOTICE TO U.S. READERS

The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are not

comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined

differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules.

Disclaimers

37

In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes,

which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of

applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC

mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period. Additionally, the SEC prohibits disclosure of oil and gas

resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not construed as reserves. For a description of the definition

of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see “Information Regarding Reserves, Resources and Operational Information” above.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This presentation contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any

of the words "expect", "anticipate", "continue", "estimate", “guidance”, "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", “budget”, "strategy" and

similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, these presentations contains forward-looking information

pertaining to the following: Enerplus' strategy to deliver both income and growth to investors and Enerplus' related asset portfolio; future returns to shareholders from both

dividends and from growth in per share production and reserves; future capital and development expenditures and the allocation thereof among our resource plays and assets;

future development and drilling locations and plans; the performance of and future results from Enerplus' assets and operations, including anticipated production levels and

decline rates; future growth prospects, acquisitions and dispositions; the volumes and estimated value of Enerplus' oil and gas reserves and contingent resource volumes and

future commodity price and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; the volume and product mix of Enerplus' oil and gas production;

securing necessary infrastructure and third party services; the amount of future asset retirement obligations; future cash flows and debt-to-cash flow levels; potential asset sales;

returns on Enerplus' capital program; Enerplus' tax position; and future costs, expenses and royalty rates.

The forward-looking information contained in this presentation reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that

Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; the general continuance

of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserve

and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and cash flow to fund Enerplus' capital and

operating requirements as needed; and the extent of its liabilities. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking

information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information and involves

known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information

including, without limitation: changes in commodity prices; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from development

plans or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans by Enerplus or by third party

operators of Enerplus' properties; increased debt levels or debt service requirements; inaccurate estimation of Enerplus' oil and gas reserves and resources volumes; limited,

unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; and certain

other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in Enerplus' Annual Information Form and Form

40-F described above).

The forward-looking information contained in this presentation speak only as of the date of this presentation, and none of Enerplus or its subsidiaries assumes any obligation to

publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Jo-Anne M. Caza

Vice President, Corporate & Investor Relations

403-298-2273

jcaza@enerplus.com

Garth Doll

Manager, Investor Relations

403-298-1218

gdoll@enerplus.com

1-800-319-6462

investorrelations@enerplus.com

www.enerplus.com

The Dome Tower

Suite 3000, 333 7th Ave SW

Calgary, AB Canada

T2P 2Z1

Investor Relations Contacts