May Investor Update - Enerplus

enerplus.com

May Investor Update - Enerplus

Investor Update

May 2013

Institutional - May 10, 2013


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 forward-looking information pertaining to the following: Enerplus' asset portfolio; future capital and

development expenditures and the allocation thereof among our resource plays and 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; the volume and product mix of

Enerplus' oil and gas production; the amount of future asset retirement obligations; future funds flow and debt-to-funds flow levels; potential asset sales;

returns 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 reflect 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 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 Form40-F described at the end of the presentation).

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.

1


Corporate Strategy

Deliver sustainable, profitable growth and income to investors

• Development of top tier growth plays and more mature foundation

assets

• Disciplined, return-based capital allocation and active portfolio

management

• Diligent cost control and operational efficiency

• Preservation of financial flexibility and strong balance sheet

2


Corporate Profile

Ticker Symbol (TSX & NYSE)

Enterprise Value (1)

Average Daily Trading Value (Q1 2013)

2013E Average Daily Production

2013E Exit Production

ERF

$4.2 billion

$24 million

82,000 – 85,000 BOE/day

84,000 – 88,000 BOE/day

• Oil and Liquids Weighting ~50%

2013E Capital Spending

$685 million

• Oil and Liquids Plays ~85%

1. Market Cap. at May 15, 2013 plus March 31, 2013 net debt of $1.1 billion

3


U.S.

40%

Improved Asset Base

Production Mix

US Oil - Bakken/Three Forks

• 4-6 years future drilling inventory

• production potential of 20-25,000 MBOE/day

US Natural Gas – Marcellus

• Doubled production in 2012

• >200 future drilling locations

Canada

60%

Canadian Oil – Waterfloods

• >1.2 billion barrels OOIP, low decline

• EOR/IOR potential with >150 future drilling

locations

Canadian

Gas

Canadian

Oil

Canadian Natural Gas - Deep Basin

• Significant acreage position in the Wilrich,

Montney and Duvernay

• 1000 future drilling locations

US

Oil

US

Gas

4


MBOE/day

Delivering Organic Growth

90

80

70

60

50

40

30

20

10

0

Q4 2012

Q3 2012

Q2 2012

Q1 2012

Q4 2011

Q3 2011

Q2 2011

Q1 2011

Oil & Natural Gas Liquids

Natural Gas

5


MMBOE

MMbbls

Delivering Reserves Growth

Total Reserves*

Crude Oil Reserves*

400

350

300

250

200

150

346 MMBOE

322 MMBOE

306 MMBOE

47% 43% 40%

225

200

175

150

125

100

75

150

MMbbls

171

MMbbls

192

MMbbls

100

50

49% 53% 55%

50

25

0

2010 2011 2012

0

2010 2011 2012

Liquids Crude Oil Natural Gas

Crude Oil

* Based on 2P company interest reserves at December 31.

6


$/BOE

Competitive Reserve Addition Costs

$45

$40

$35

$30

$25

$20

$15

Finding and Development Costs

$39.04

$36.71

$26.26

$24.21

$17.22

$14.88

2012 Highlights:

• Continued trend of improving

F&D costs - down 8% in 2012

• 66% of reserve additions from

crude oil

• Replaced 283% of 2012 oil

production

$10

$5

$0

2010 F&D* 2011 F&D* 2012 F&D*

• Acquisition and divestment

activity had a positive impact,

resulting in FD&A of

$22.92/BOE including FDC

Excl. Future Development Capital

Incl. Future Development Capital

* Based on 2P company interest reserves at December 31

7


$ Millions

Delivering Funds Flow Growth

$700

$600

$500

$400

$300

• Funds flow driven by 25%

increase in oil production from

2011 to 2013E

• Expect funds flow growth and

improvement in adjusted

payout ratio in 2013

• Balance sheet remains strong

$200

$100

$0

2011 2012

8


Debt to Funds Flows (x)

Preserving Financial Strength

2.5

• Strategic steps taken in 2012 to

manage our balance sheet:

• $331 million equity issue

2.0

1.6x

1.7x

• $405 million private

placement of long-term debt

1.5

• Dividend reduced to

$0.09/share

1.0

• Implemented stock dividend

program

0.5

0.0

2011 2012

• Non-core asset sales

totaling $423 million

9


$ Millions

Debt Composition

Unutilized

Capacity

$686MM

Senior

Notes*

US$742MM

CAD$70MM

$700

$600

Senior Note Maturities*

$585

$500

$400

$300

Bank

Debt

$314MM

$200

$100

$0

$46 $46

$91

$45

2013 2014 2015 2016 2017 2018 and

beyond

• $1.1 billion outstanding debt as of March 31, 2013 comprised of:

• Senior notes rated NAIC 2 and rank equally with bank credit facility

• Weighted average rate of 5.8%

• Credit facility is a $1 billion unsecured, covenant based facility maturing 2015

• Current borrowing rates of less than 3%

* Notional outstanding principal as at March 31, 2013, US$ amounts converted at $1 US/CDN

10


2013 Plans

Improve capital efficiencies by reducing drilling and completion costs and

improving operational execution

Continue to develop and grow production in Fort Berthold, Canadian

waterfloods, Marcellus

Modest appraisal activities in the Wilrich, Duvernay and Montney

Sell non-core assets to improve focus of portfolio, fund further portfolio

development and preserve financial strength

Improve sustainability, maintain the dividend and deliver growth in cash

flow

11


2013 First Quarter – Results on Track




Strong production performance

Disciplined capital spending – cost savings in key areas

Maintaining all guidance targets for the full year

Q1 2013

2013 GUIDANCE

Funds Flow

$173 million

Adjusted Payout Ratio * 126% 125%

Debt to Funds Flow 1.7x


% of net after royalty production

2013 Cash Flow Protection

Crude Oil Hedge Positions*

Natural Gas Hedge Positions*

70%

60%

64%

70%

60%

50%

50%

40%

40%

33%

33%

30%

Hedged at

$100.44/bbl

30%

8% at

US$3.45

8% at

US$3.85

25%

20%

10%

15%

Hedged at

$92.60/bbl

20%

10%

14% at

$3.59

11% at

$3.17

14% at

$3.59

11% at

$3.17

US$4.17

0%

2013 2014

0%

Apr-Jun 2013 Jul-Dec 2013 2014

WTI Swaps

AECO Puts AECO Swaps NYMEX Swaps

* As of April 24, 2013, Based on weighted average price (before premiums), average

annual production of 82,000 – 85,000 BOE/day for 2013, less royalties of 21%.

13


Production Composition and Differentials

2013E Production

2013E Crude Oil Composition

US Gas

16%

US Oil

24%

Canada

Heavy

25%

Canada Gas

34%

Canada

Oil

22%

Canada

Medium

12%

Canada

Light

11%

US

Light

52%

NGLs

4%

2013 Estimated Price Differential to WTI

Original Budget

Current Forecast*

US Light US$13.25 US$12.00

Canada Light US$13.00 US$9.00

Canada Medium US$16.00 US$14.00

Canada Heavy US$21.00 US30.00

* February 2013 estimates 14


Continued Focus on Portfolio Optimization

Rationalization of non-core assets to improve operational focus,

profitability and provide funding source for growth areas

YTD 2013 - sold 600 BOE/day of non-operated, low working interest oil

production from Southeast Saskatchewan and Alberta for $58 million.

Currently marketing 1,300 BOE/day of non-core assets for potential sale in

2013

Acquisition strategy to expand core areas to improve concentration, scope

and profitability

15


Significant Value Creation Delivered

from A&D Activity

Sleeping Giant

Acquisition

Manitoba

Sale

Purchase Price ($‘000s) $118,000 $218,000

Working Interest 90% 52%

Funds Flow multiple 4.5 7.0

$/BOE/day $84,000 $142,000

Production (BOE/day) 1,558 1,550

Operating Costs ($/BOE) $5.61 $14.32

Recovery to date ~8% ~21%

Discovery date 1996 1951

Continuing to focus on core areas with better operating metrics

Based on internal evaluations and pricing at time of transaction Dec/2012

16


Market Sentiment Improving

Delivery of 2012 targets and improving natural gas outlook

YTD 2013 total return of 25%*

Current analyst consensus*:

• 11 buys, 5 holds, 0 sell

• Average target price of $17.63/share

Increasing institutional ownership

• 33% institutional ownership, up from 30% at year end

* As of May 15, 2013

17


Core Oil Assets


Top Tier Light Oil Play in North Dakota

Current Operated and Non-Operated Locations

OOIP

17 – 22 MMbbls/1280 DSU

Net Acreage (90% WI) ~69,000 (108 sections)

2012 P+P Reserves 86.1 MMBOE

2012 Contingent Res.

Est.

Future Drilling

Locations

2013E Average

Production

33.5 MMBOE

>130 (2P & CR)

16,000 BOE/day

• Concentrated land position in North Dakota

– Dunn & McKenzie counties

• Prospective for Bakken and Three Forks

throughout entire acreage positions

• Average ~90% operated working interest

• 5 – 7 years drilling inventory at current pace

19


MBOE/day

Fort Berthold: Delivering Organic Oil

Growth

16

14

12

10

8

6

4

2

-

Q1 2013 record production of

over 14,500 BOE/day

2010 2011 2012 Q1 2013

• Expected to exit 2013 at

18,000 BOE/day

• Expect to drill and

complete 20 - 25 net wells

(2/3 Bakken, 1/3 Three

Forks)

• Focused on improving costs

and efficiencies

• Accounts for 25% of

corporate 2P reserves

• Future growth potential of

33.5 MMBOE of contingent

resource

20


MBOE

Cost Effective Reserves Growth at

Fort Berthold

• Total 2P reserves have nearly quadrupled

since 2010 at Fort Berthold

100,000

90,000

80,000

70,000

60,000

• 86.1 MMBOE at end of 2012, up 53%

from YE 2011

• Added 34.2 MMBOE of reserves at

F&D cost (incl. FDC) of

$25.38/BOE

50,000

40,000

30,000

20,000

10,000

0

2010 2011 2012

Proved Developed Producing Proved Developed Not Producing

Proved Undeveloped

Probable

• 50% proved with 83 net PUD

locations

• 2012 recycle ratio of 2.0 times

• 33.5 MMBOE of assessed contingent

resources at Fort Berthold at end of 2012

• 12.1 MMBOE in the Bakken

• 21.4 MMBOE in the Three Forks

21


Fort Berthold Long HZ Well Performance

Well results in line with expectations

5 4 4

6

3

The range of EURs is dependent upon zone

(Bakken or Three Forks) and well density.

EURs

Well Costs

500 – 800 Mbbls

$11.5 million

Projected IRR 20% - 53%

7

Break-Even Cost

WTI US$50 - $66/bbl

26

27

wells

23

9

11

17 15

22 19 3

6

2

1

NPV per well (10%)

$3.7 - $13 million

• Currently testing increased

frac size using white sand

for the same cost as ceramic

8

9 wells

• Production data as of April 2013

• Well costs reflect drill, complete and tie-in. Economics based on US$90 WTI constant price (10,000 ft

depth, 9600 ft lateral extensions, 29 frac stages, high strength ceramic proppant)

22


Three

Forks

Middle

Bakken

Three

Forks

Middle

Bakken

Fort Berthold Well Spacing (1280 acres per drill spacing unit)

2P + CR (EUR)

Potential Upside

800 800

? ? ?

?

Lower Bakken

Lower Bakken

500 500

? ? ?

Estimated Recovery:

• 2.7 million bbls/DSU

• 12-16% recovery factor

• 33.5 MMBOE CR estimate assumes land

utilization of:

• Bakken – 90%

• Three Forks – 75%

• 86.1 MMBOE 2P Reserves:

• only 13% of DSU’s booked to 4 wells/DSU

• include 83 net PUD locations and 74 net

developed producing wells

Bakken OOIP:

Estimated Recovery:

• 3-4 million bbls/DSU

• up to 18% recovery factor

Three Forks OOIP:

9 – 12 million bbls/DSU

8 – 10 million bbls/DSU

23


Excess Takeaway Capacity in North Dakota

• ~20% of our US Bakken production transported on rail in 2013, ~80% through pipelines

• ~10% is exposed to LLS pricing

• Q1 2013 realized US crude oil diffs were $6.10/bbl below WTI

Excess

takeaway

capacity

24


Significant Value Creation Delivered

from A&D Activity

Sleeping Giant

Acquisition

Manitoba

Sale

Purchase Price ($‘000s) $118,000 $218,000

Working Interest 90% 52%

Funds Flow multiple 4.5 7.0

$/BOE/day $84,000 $142,000

Production (BOE/day) 1,558 1,550

Operating Costs ($/BOE) $5.61 $14.32

Recovery to date ~8% ~21%

Discovery date 1996 1951

Continuing to focus on core areas with better operating metrics

Based on internal evaluations and pricing at time of transaction Dec/2012

25


Low Decline Canadian Crude Oil Assets

Growth potential with low average decline rate of ~12%

• 25% of total production with

significant free cash flow

• Production growth of 8% in 2012

• Over 1.2 billion barrels original oil

in place with 22% recovered to

date

• Primarily mature fields under

waterflood with modest growth

potential

• 60 million barrels of contingent

resource from EOR and IOR

potential

• 2 polymer projects underway

26


Defining the IOR/EOR Opportunity

ASSET

2013E

PRODUCTION

(BOE/DAY)

OOIP

(NET)

(MMBBL)

TOTAL

RECOVERED

(MMBBL)

2012

YE 2P

RESERVES

(MMBOE)

CONTINGENT RESOURCE

(MMBBL)

IOR EOR TOTAL

TOTAL

RECOVERABLE

2013 NET

OPERATING

INCOME

Medicine Hat, AB 4,470 224 18.8 21.1 1.5 22.4 23.9 28% ~$42/BOE

Giltedge, AB 1,870 158 18.6 10.5 7.7 13.9 21.6 32% ~$38/BOE

Freda/Skinner

Lake/Neptune, SK

3,370 106 15.2 12.3 5.1 0 5.1 31% ~$48/BOE

Brooks 3,240 230 58.8 7.5 3.5 0 3.5 30% ~$28/BOE

Cadogan, AB 620 43 4.4 2.5 3.1 0 3.1 24% ~$46/BOE

Kingsford 210 27.2 4.1 0.7 1.9 0 1.9 25% ~$42/BOE

Pouce Coupe 720 17.5 3.5 1.6 1.2 0 1.2 36% ~$23/BOE

Sub-Total 14,500 806 123.4 56.2 24.0 36.3 60.3

Other Canadian Oil properties without Contingent Resources:

ASSET

2013E

PRODUCTION

2012 YE 2P

RESERVES

(MMBOE)

2013 NET

OPERATING

INCOME

Pembina 5 Way 1,840 20.8 ~$27/BOE

Joarcam 1,040 3.1 ~$12/BOE

Progress 730 1.9 ~27/BOE

27


2013 Canadian Oil Capital Program

2013E Capital by Waterflood Prospect

2013E Capital Spend Allocation

Other

13%

Pembina 5 Way

9%

Med Hat Glauc C

25%

Plant & Facilities

42%

Brooks

9%

Giltedge

10%

Pouce Coupe

11%

Freda Lake/

Neptune

23%

Drilling/

Completions

58%

28


Waterflood Success Story - Medicine Hat Glauc C

OOIP

224 MMBbls

Recovery Factor to Date ~9%

Polymer

Project Area

Cumulative Production

P+P Reserves (Dec 31, 2012)

Best Estimate Contingent

Resource (Dec 31, 2012)

Oil Quality

2013E Avg. Production

~19 MMBbls

21.1 MMBOE

IOR 1.5 MMBOE

EOR 22.4 MMBOE

11° to 18° API

4,470 BOE/day

72% WI across ~14 sections

• 66% reinvestment over past 5 years has

grown production by over 60%

• Polymer project has estimated incremental

recovery of 10% (22.4 MMBOE)

• Improved waterflood management has

estimated incremental recovery of 3%

(1.5 MMBOE)

29


Jan 2008

May 2008

Sep 2008

Jan 2009

May 2009

Sep 2009

Jan 2010

May 2010

Sep 2010

Jan 2011

May 2011

Sep 2011

Jan 2012

May 2012

Sep 2012

Jan 2013

Average Daily Production (BOE/day)

Medicine Hat Glauc C – Production

5,000

4,500

4,000

~60% growth achieved over

5 years with ~65% reinvestment

3,500

3,000

2,500

2,000

1,500

1,000

500

• Implemented new waterflood

development strategy in 2009

• Numerous battery upgrades from

2009-2012

• Moved to 100m inter-well spacing

May 2012 polymer pilot injection

-

30


$ Million

BOE/day

Success of IOR/EOR at Medicine Hat

$50

$45

$40

$35

$30

$25

$20

$15

$10

$5

$0

66%

67%

61%

21%

2009 2010 2011 2012

Capital Free Cash Flow Avg Daily Production

3,500

3,000

2,500

2,000

1,500

1,000

500

-

2P

NPV 10%

$296mm $298mm $297mm $340MM

Waterflood optimization and early results from polymer EOR project have increased

production and NPV while generating significant free cash flow for reinvestment.

31


Core Natural Gas Assets


Marcellus: Reduced Spending on Dry Gas

Bradford/Sullivan Counties

• 40% of 2013 capital budget

Susquehanna/Wyoming Counties

• 25% of 2013 capital budget

Lycoming County

• 20% of 2013 capital budget

• 44,000 net non-operated acres with an approximate 20% working interest

• Major non-op partners are EXCO and Chief

• $80 million capital budget for 2013

• Expect majority of core non-operated acreage retained by end of year

Operators:

EXCO Resources

Chief O&G & Chesapeake

33


MMcfe/day

Delivering Growth in the Marcellus

Q1 2013 record production of

over 79 MMcf/day

• Represents over 25% of

corporate natural gas

production

80

70

60

50

40

30

20

10

• Location and low cost structure

delivers attractive netback of

~$2.50/Mcf

• Accounts for 27% of corporate

2P natural gas reserves

• Future growth potential of 1.3

Tcfe of contingent resource

-

2010 2011 2012 Q1

2013

34


NE Pennsylvania Well Performance

Wells in top tier acreage significantly outperforming type curve

Susquehanna

Bradford

8 Bcf

E Lycoming

6 Bcf

W Lycoming

* Production data as of April 9, 2013 . Well counts shown are on a gross basis.

35


Rate of Return

Marcellus Economics

70%

60%

$2.35 - $2.75/Mcf breakeven in Bradford &

Susquehanna with 10 – 12 Bcf type wells

50%

$5 Gas

40%

30%

$4 Gas

20%

10%

$3 Gas

0%

6 8 10 12

EUR (bcf)

* Returns assume well cost of $7.0 million

36


An Abundance of Deep Gas Opportunities

Montney

34,000 net acres of

undeveloped land, 100% WI

• Approximately 188,000 net acres

of high working interest land

• Significant potential in Wilrich,

Duvernay and Montney

Stacked Mannville

71,000 net acres of land

(54,000 net acres of land

in the Wilrich, majority

100% WI)

• 1,000 potential future drilling

locations

• Successful drilling results to date in

Wilrich

• Identified 283 Bcfe contingent

resources in 2012

Duvernay

83,000 net acres of

undeveloped land, 100%

WI

• Over 100 future HZ locations

for future development

• Joint venture potential in Duvernay

& Montney

37


Deep Gas – Wilrich

Contiguous land blocks in highly prospective regions

Key properties

Ansell, Minehead, Hanlan

Net Acreage (acres)

~54,000 acres (84 sections,

majority 100% WI)

Future HZ Drilling Locations Over 100

Est. EUR/Well

4.0 - 6.0 Bcfe

2012 Contingent Res. Est. 283 Bcfe

- 57 net drilling locations

• 2013 capital program of ~$40 million focused

primarily in Ansell

• 2 successful wells drilled in Q1

• #1 had IP30 of 6 MMcf/day

• #2 tested at peak rate of 35 MMcf/day

at 15.3 Mpa over 17 hour period,

currently flowing 17 MMcf/day

• Breakeven cost of


Cumulative Production (MMcf)

Wilrich – Positive Drilling Results

5.0 Bcf Well 6.0 Bcf Well

AECO

($/Mcf)

IRR

%

Pay

out

(Yrs)

NPV

10%

($MM)

IRR

%

Pay

out

(Yrs)

NPV

10%

($MM)

$4.00 54 1.8 6.5 67 1.6 8.6

$3.00 31 2.6 3.4 40 2.2 5.1

1,800

1,600

1,400

1,200

2 Wells

1 Well

$2.00 11 4.7 0.2 18 3.7 1.4

1,000

Capital* $7.1 million $7.1 million

30 Day

IP

5,300 Mcf/day 6,000 Mcf/day

Liquids 7 bbls/MMcf 7 bbls/MMcf

BESC $1.93/Mcf $1.61/Mcf

800

600

400

200

0

3 Wells

0 1 2 3 4 5 6 7 8 9 10 11 12 13

Months Producing

• Type curves are based on offset data and are

supported by our well results

Average Actual Production 6.0 Bcf Type Curve

5.0 bcf Type Curve

39


Duvernay Shale – Willesden Green

Enerplus

40


Duvernay: Emerging Top Quality Liquids-Rich

Resource Play

Key Properties

Willesden Green, AB

Net Acreage ~83,000 acres (130

sections, 100% WI)

Est. OGIP

Est. Density

Est. EUR/Well

Est. Initial Hz Well Cost

~65 Bcf/section

4 wells/section

3.5 Bcf

~$15 million

• Analogous rock characteristics to the Eagleford

• Prolific over-pressured Devonian source rock (~56

MPa)

• Increased industry activity in Willesden Green

region providing strong geological control and

increased confidence in play

Est. 30 day IP

Est. Avg. Liquids*

~4.4 MMcf/day

50 –100 bbls/MMcf

• Equivalent thermal maturity and depth to proven

liquids-rich Kaybob area

• 4 well/section development provides us with

over 400 future Hz drilling locations

• One vertical strat well drilled in late 2012 – results

confirm liquids rich window

• Vertical delineation planned in 2013 to better define

optimal liquids window for future development

* Actual wells may yield higher or lower liquids ratio than the average range

41


Montney – Cameron/Julienne Creek

Key Properties

Cameron/Julienne Creek

Net Acreage ~33,000 acres (+50

sections, 100% WI)

Estimated OGIP

150 Bcf/section

Future Hz Drilling

Locations

500+

Montney Vert. Test Well

and Hz Licensed Wells

North Montney

Regional Pool

Est. EUR/Well

4.0 – 6.0 Bcfe

• 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

42


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 19.6 3.7 1.6 31.2 2.6 3.3 44.0 2.0 4.8

$3.00 9.2 6.2 (0.1) 17.0 4.2 1.2 25.1 3.1 2.5

$2.00 - - (2.2) 4.5 9.3 (1.1) 9.8 6.4 (0.0)

Capital $6.2 million $6.2 million $6.2 million

30 Day IP 3,700 Mcf/day 4,600 Mcf/day 5,500 Mcf/day

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

BESC $3.05/Mcf $2.34/Mcf $2.01/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

43


Why Enerplus?

Financial strength and improving sustainability

• Capital discipline, improving costs, capital efficiencies and focus

• Delivering attractive reserve, production and funds flow growth

Compelling assets in Canada and U.S.

• Low decline asset base with significant inventory of early stage

opportunities to deliver future growth in reserves and production

Compelling dividend

• Current yield of ~7%

Attractive valuation relative to asset value and peers

• Upside exposure to improving natural gas prices with growing NYMEXbased

natural gas production

44


Supplemental Information


Attractive Valuation

Enerplus (2)

Canadian

Competitor Average (2)

(Range)

U.S.

Competitor Average (3)

(Range)

2013E Price/CF 3.9x 6.7x

(2.4x – 9.9x)

5.4x

(2.9x – 11.5)

2013E EV Multiple (1) 5.7x 8.1x

(4.4 – 10.6x)

6.7x

(4.1x – 12.9x)

2013E EV per Daily BOE $49,000 $84,000

($49,000 – $146,500)

$126,000

($78,000 – $172,500)

2013E Debt to Cash Flow 1.9x 2.0x

(1.0x – 3.1x)

1.7x

(0.9x – 2.9x)

Yield 7.8% 7.4%

(2.5% - 11.8%)

0.1%

(0% - 0.6%)

(1) Canadian Peers calculated using EV/DACF incl. hedging. US Peers calculated using EV/EBITDAX

(2) RBC Capital Markets research dated April 29, 2013. Peer group includes ARC, Baytex, Bonavista, Crescent Point, Pengrowth, Penn West, PetroBakken and Peyto. RBC

Pricing Assumptions: WTI 2013 US$97.00/bbl; AECO 2013 CDN$3.40/Mcf; 2013 US$/CDN$00.994

(3) RBC Capital markets research dated May 1, 2013. Peer group includes Oasis, Kodiak, Continental, Whiting, Range and EOG. RBC Pricing Assumptions: WTI 2013

US$97.00/bbl; NYMEX US$3.81/Mcf

46


Commitment to Dividend Model

Total Retail

67%

Canadian

Retail

19%

US/Intl Retail

48%

Investor Composition

As of April 24, 2013

Total Institutional

33%

US/Intl

Institutional

13%

Canadian

Institutional

20%

Capital markets place higher valuation on

dividend paying energy companies

• Canadian energy yield companies trading

at ~2.0x EV/DACF and ~2.1x cash flow

multiple premiums to senior Canadian and

US energy names*

Investor composition supports dividend

model

• 2/3 rds of shares are held by retail investors

Have no plans to adjust monthly dividend

Sale of non-core assets, improvement in

natural gas prices and reduced capital

spending improving sustainability

* RBC Capital Markets reports dated May 1 and May 10, 2013

47


2013 Capital Budget Sensitivities

2013 Sensitivities

(as of April 24, 2013*)

Est. effect on

2013 Funds Flow

($ Million)

Change of $5.00/bbl WTI crude oil $16

Change of $0.50/Mcf natural gas $20

Change of 1,000 BOE/day production $3

Change of $0.01 in the US$/CDN$ exchange rate $3

* The sensitivities above reflect our forecasts , outstanding commodity contracts,

and are based on forward markets as at April 24, 2013.

48


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

• Generally 100% of the value of the dividends earned by non-residents used

to purchase shares (no withholding tax applied)

SDP participation is completely optional

49


Enerplus Share Ownership

Investor Composition

Geographic Composition

Total Retail

67%

Total Institutional

33%

Canadian

Retail

19%

US/Intl

Institutional

13%

US/Other

61%

Canada

39%

US/Intl Retail

48%

Canadian

Institutional

20%

As of April 24, 2013

50


Advisories

Assumptions

All amounts are stated in Canadian dollars unless otherwise specified.

Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent

This presentation contains references to "BOE" (barrels of oil equivalent), "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 "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "F&D costs", “FD&A

costs”, “recycle ratio” and “operating netback” 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 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. “Operating netback” is calculated as revenues

after deducting royalties, operating costs and transportation. A “recycle ratio” is calculated as F&D costs divided by operating netback.

Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the terms "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 IFRS. Therefore, these measures, as defined by Enerplus, may not be comparable to similar

measures presented by other issuers.

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, 2012, 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, 2012 ("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.

51


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. "Contingent

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

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

commercially recoverable due to one or more contingencies. Contingencies may include factors such as ultimate recovery rates, economic, legal, environmental, political

and regulatory matters or a lack of markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associated with a

project in the early evaluation stage. Enerplus expects to develop these contingent resources in the coming years however it is too early in their development for these

resources to be classified as reserves at this time. All of our contingent resource estimates are economic using established technologies and under current commodity

price assumptions used by our independent reserve evaluators. 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, 2012. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the

best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best

estimate.

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

Marcellus shale gas properties, our Fort Berthold properties, our Wilrich natural gas properties and a portion of our Canadian crude oil properties as reserves and the

positive and negative factors relevant to the “contingent resource” estimates, see our AIF for the year ended December 31, 2012 (and corresponding Form 40-F) dated

February 22, 2013, 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 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 reflect total finding, development and acquisition costs related to its reserves additions for that year. See "Non-GAAP Measures"

above.

52


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, 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 “Information

Regarding Reserves, Resources and Operational Information” above.

53


Investor Relations Contacts

Jo-Anne M. Caza

Vice President, Corporate & Investor Relations

403-298-2273

jcaza@enerplus.com

Garth Doll

Manager, Investor Relations

403-298-1218

gdoll@enerplus.com

1-800-319-6462

investorrelations@enerplus.com

www.enerplus.com

The Dome Tower

Suite 3000, 333 7th Ave SW

Calgary, AB Canada

T2P 2Z1

54

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