The Game Plan

Investor Update

November 2012

• Focused on delivering a combination of moderate organic growth and

income to investors

• Current yield ~8%

• Own a portfolio of oil and gas properties in some of the best resource plays

in North America:

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

• producing assets that generate steady cash flow and offer development

opportunity

• Maintain a strong financial position

Corporate Overview

1

Corporate Profile

• Ticker Symbol (TSX & NYSE) ERF

• Enterprise Value (1) $3.5 billion

• Average Daily Trading Value (through Q3 2012) $49 million

• 2012E Average Daily Production 82,000 BOE/day

• 2012E Exit Production 85,000 – 88,000 BOE/day

– Oil and Liquids Weighting ~50%

– Canada/US 66%/34%

• 2012E Capital Spending $850 million

– Oil and Liquids Weighting ~75%

• Q3 2012 Debt to Trailing 12 Months Funds Flow 1.9x

– Proforma Manitoba asset sale 1.5x

1. Market Cap. at November 9, 2012 plus September 30, 2012 net debt of $1,119 million less $220 million proforma Manitoba

asset sale expected to close late December 2

Our Assets

3

2012E Production

Marcellus

Shale Gas

Other Gas

Tight

Oil

Montney, Stacked

Mannville and

Duvernay

Bakken/Three Forks

Marcellus Shale

Waterfloods

Other

Oil

Deep

Gas

Waterfloods

18%

9%

24%

23%

20%

6%

Delivering Organic Production Growth

4

• Adjusted annual production

guidance to 82,000 BOE/day in

2012 due to slow down in

Marcellus activity

• Expected annual growth of 9%

• Adjusted exit production guidance

to 85,000 to 88,000 BOE/day

• Expected exit growth of 4 - 7%

• Oil growth of 16% since Q4 2011 -

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 2012 Exit

BO

E/d

ay

Oil Gas

77,221 79,190

82,108

85,000 –

88,000

81,573

73,245

Improved Financial Flexibility

5

Senior Notes US$744MM & CAD$70MM

Bank Debt $307MM

Unutilized Capacity $693MM

• Strategic steps taken in 2012 to manage our

balance sheet:

• $330 million equity issue in February

• $405 million private placement of long-term

debt in May

• 7 to 12 year terms at 4.4%

• Dividend reduced to $0.09/share

• Implemented stock dividend program

• Laricina equity position sold in August for

$141 million

• Pending sale of non-core Manitoba assets for

$220 million expected to close in December

• $1.0 billion bank credit facility

• Undrawn ~$693MM*

Debt composition*

* Q3 2012 outstanding debt does not include expected proceeds from Manitoba asset sale

6

Protecting our Cash Flow

63% 58%

0%

20%

40%

60%

80%

100%

2012 2013

% o

f n

et

aft

er

roya

lty p

rod

uc

tio

n

Crude Oil Hedge Positions*

* Based on weighted average price (before premiums), average annual production (excluding impact of Manitoba asset sale) assumptions of

82,000 BOE/day for 2012 and 2013, less royalties of 21%

17%

0%

20%

40%

60%

80%

100%

2012 2013

% o

f n

et

aft

er

roya

lty p

rod

ucti

on

7%

Natural Gas Hedge Positions*

• Costless collars in

place with floor of

$2.12/Mcf and

ceiling of $2.91/Mcf

• Combination of swaps

and purchased puts

averaging $3.31/Mcf

• Combination of

swaps and

purchased puts

averaging

US$96.17.bbl

• Fixed price swaps

averaging

US$100.84/bbl

Fort Berthold Leads the Charge in Oil Growth

7

Key Facts

Net Acreage (90% WI) ~70,000 (110 sections)

2011 P+P Reserves 55.4 MMBOE

2011 Contingent Res. Est. 49 MMBOE

Future Drilling Locations 130+

2012 Q3 Production 12,800 BOE/day

Current Operated and Non-Operated Locations

• Concentrated, top tier land position in North

Dakota – Bakken and Three Forks

• Average ~90% working interest

• Recent QEP Energy $1.4 billion purchase of

adjacent/overlapping Bakken acreage

position indicates positive valuation

comparison

• Production growth potential to over 20,000

BOE/day over next 3-4 years

8

Fort Berthold Operations Update • Currently have 66 net operated wells on production with two thirds tied in to gathering

system

• Expect to have 4 more wells producing by year end

• Reduced size of fracs and amount of fluid/proppant pumped per stage to reduce costs,

however drop in performance did not substantiate cost savings

• Current completions reverting back to 28-29 stages, 90,000 lbs of proppant per stage across

9,800 foot lateral length

• Costs ~$5 million to drill and ~$6.5 million complete long hz well before facilities or tie-in, in line

with non-op activity

• Greater confidence in prospectivity of Three Forks with 14 wells on production

• 4 wells with more than 6 months production tracking type curve (70% of a Bakken long)

• Best well is on pace to produce 100,000 bbls in 1st year, comparable to Bakken type well

• 2012 drilling program primarily single well pads to manage lease expiries

• 2013 – expect a 2 rig program with a reduced capital program resulting in modest

production growth

9

Fort Berthold Well Results To Date

19 wells

18

16

10 6

5

4

3

6 wells

5

4

2

1

21

wells

18 12

7

6

5

7

7

5

4 2

1

8 wells 6

4

3

2 1

Fort Berthold Economics

10 * Economics include associated gas, before tax in US dollars with Bakken differential of US$17.00/bbl, declining to $13.00 in

4 years. Royalties average 19.5%, plus state production and extraction tax of 5% for first 5years, followed by 9% thereafter

52 52

42

36

78

0

20

40

60

80

100

120

140

YE 2011 Booked Net P+P-UD Bakken Contingent NetLocations

Three Forks Contingent NetLocations

Total Booked Reserves &Contingent Resource

Multi-Year Drilling Inventory at Fort Berthold (Year End 2011)

11

Contingent Resource Locations

130

Locations

• 4 to 6 years of drilling inventory assuming 20 to 30 wells drilled per year

• Additional upside possible from increased density and land utilization

Locations

Locations

12

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

Estimated Recovery:

• 1.6 million bbls/DSU

• 13-18% recovery factor

Estimated Recovery:

• 2.7 million bbls/DSU

• 12-16% recovery factor

• CR estimate assumes land

utilization of:

• Bakken– 90%

• Three Forks – 35%

Estimated Recovery:

• 3-4 million bbls/DSU

• up to 18% recovery factor

Early Learnings:

• Communication occurring between the Bakken and Three

Forks during completion; potentially during production

• Bakken wells appear to outperform – Three Forks

contribution?

• 2 wells/DSU likely underdeveloped

Bakken OOIP:

• 9 -12 million bbls/DSU

Three Forks OOIP:

• 8 -10 million bbls/DSU

Lower Bakken

800 800 800 800 ? ?

560 560

? ?

Mid

dle

Bakken

Thre

e

Fork

s

2P (EUR) 2P + CR (EUR) Potential Upside

? ? ?

Mid

dle

Bakken

Thre

e

Fork

s

Lower Bakken Lower Bakken

Delivering Organic Oil Growth at Fort Berthold

13

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012

BO

E/d

ay

Low Decline Canadian Waterflood Assets

Key Facts

OOIP* ~1.2 billion barrels (net)

P+P Reserves (YE 2011*) 82 million barrels net

(26% recovery)

Recovery to date* 22%

Best Est. Contingent

Resources*

53.5 million barrels

Average Oil Quality 30° API

Q3 2012 Production ~16,769 BOE/day

14

• Significant future drilling potential as well as enhanced oil recovery opportunities

• Moderate growth outlook of ~5% per year

14 * As at Dec. 31, 2011 and updated to reflect Manitoba asset sale transaction expected to close December 2012

15

0

5

10

15

20

25

2005AA

2006AA

2007AA

2008AA

2009AA

2010AA

2011AA

2012eAA

2012eExit

MB

OE/

day

Stable Crude Oil Production Base from Waterfloods

• Low base decline of ~12%

• ~50% of net operating

income reinvested to

maintain production

• 2012E annual production:

~17,000 BOE/day, +2%

from 2011

Sold ~2,800 non-core

BOE/day

* 2012 production estimates not adjusted for Manitoba asset sale expected to close December 2012

16

Marcellus: Retaining Leases for Future Value Capture

• 2012 activity driven by focus on lease

retention in non-operated counties –

Bradford, Susquehanna and Lycoming

• ~80% of drilling activity in 7-11 Bcf areas

with IRRs of 15% - 30%*

• Expect to have close to 2/3 of core non-

operated acreage held by production by

year-end

• Reducing acreage positions in

operated areas in Maryland and

West Virginia

• Non-operated on-stream activities delayed

due to weak natural gas prices resulting in

lower than expected production

• November 2012 production ~48 MMcf/day,

up 90% year to date

EXCO Resources

Chief O&G & CHK

• 47,000 net non-operated acres with 20% avg. working interest

• Major non-op partners:

• EXCO (22% WI)

• Chief (18% WI)

* Rates of return estimated using Oct 11, 2012 forward prices for NYMEX natural gas

Northeast Pennsylvania Well Performance

17

Marcellus Economics

18

19

• Approximately 175,000 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 liquids rich zones

• 2012 capital focused on delineation

• Duvernay – 1 vertical strat well

• Montney - 1 vertical strat

• Stacked Mannville (Wilrich) – 2 hz

producers

19

Large, long tenure, high

working interest land holdings

An Abundance of Deep Gas Opportunity

Montney Potential

• 33,000 net acres of

undeveloped land

Stacked Mannville Potential

• 70,000 net acres of land

(42,000 acres undeveloped)

Duvernay Potential

• 72,000 net acres of

undeveloped land

20

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

• Successful 2012 well tests support future

development of this asset

Key Facts

Key properties Pine Creek to Hanlan

Net Acreage (acres) ~70,000 acres (110 sections)

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

20

21

Deep Gas: Wilrich Type Curve and Performance

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

$2.00 11 4.7 0.2 18 3.7 1.4

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

• Type curves are based on offset

data and are supported by our well

results

* Capital assumes pad drilling

21

0

200

400

600

800

1,000

1,200

1,400

1,600

0 1 2 3 4 5 6 7 8 9 10C

um

ula

tiv

e P

rod

ucti

on

(M

Mcf)

Months Producing

Positive Drilling Results

Average Horizontal Production

6.0 Bcf Type Curve

5.0 bcf Type Curve

3 Wells

2 Wells

1 Well

22

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

23

Deep Gas: 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

23

Duvernay Emerging as a Top Quality Liquids-Rich

Resource Play • Analogous rock characteristics to the Eagleford

• Prolific over-pressured Devonian source rock

(~56 MPa)

• We own ~113 net sections (100% W.I.) within the

gas condensate window:

• equivalent thermal maturity and depth to proven liquids-

rich Kaybob area

• 4 well/section development provides us with over 400

future Hz drilling locations

• Increased industry activity in Willesden Green region

providing strong geological control and increased

confidence in play

• Our lands are intersected by major pipelines

providing proximal egress options, reduced tie-in

costs and numerous options for product marketing

• Focused on evaluation in 2012 with one vertical strat

well drilled in October and 1st Hz planned for Q1

Key Facts

Key Properties Willesden Green, AB

Net Acreage ~72,000 acres (113 sections)

Est. OGIP ~65 Bcf/section

Est. Density 4 wells/section

Estimated

EUR/Well

3.5 Bcf

Early Hz Well Cost ~$15 million

30 day IP ~4.4 MMcf/day

Est. Liquids 75-100 bbls/MMcf

(high % condensate)

24

25

Duvernay Shale – Willesden Green

25

ERF Proposed Hz 11-27-044-09W5

ERF Vt Well 11-26-045-09W5 RR Oct. 26, 2012

Q1 2013

Why Enerplus?

• Demonstrating organic production growth

• Significant inventory of oil and gas opportunities in portfolio to

deliver future growth in reserves and production

• Strong financial position with significant unutilized credit capacity

• Attractive, more sustainable dividend providing yield of ~8%

• Compelling valuation relative to asset value and peers

26

The Game Plan Supplemental Information

175% Organic Reserve Replacement in 2011

28

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 in accordance with

Canadian reporting requirements under National Instrument 51-101 29

$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

29

30

North Dakota Takeaway Capacity

30 Does not include: Enbridge Sandpiper looping of existing line (~200 bbls/d to Superior) or Saddle Butte High Prairie line

(~200 bbls/d to Clearbrook) which is not yet approved.

North Dakota

31

Bakken Oil Differentials

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

2013

• ~30% of our US Bakken production transported on rail, ~70% through pipelines

• ~15% is exposed to LLS pricing

• As more crude accesses these premium markets, we expect this differential to

narrow

-$20

-$16

-$12

-$8

-$4

$0

$4

Jan Feb Mar Apr May Jun Jul Aug Sep Oct

Oil sold into pipelineat Bakken basket price

Oil sold into rail

* Diffs do not reflect cost of trucking

Recent benefit of rail deliveries vs. pipeline in 2012

32

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

• Replaced Canadian DRIP

• Early participation of about 18% of dividends paid

– Up from 11% for first 5 months of 2012 under old DRIP

Disclaimers

33

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 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.

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

34

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

35

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

36