Jefferies 2014 Global Energy Conference November 12, 2014

ERF: TSX & NYSE

1

FORWARD-LOOKING INFORMATION AND STATEMENTS

This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking

information"). The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "objective", "ongoing", "may", "w ill", "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: expected 2014 and 2015 average production volumes and the anticipated production mix; the

proportion of our anticipated oil and gas production that is hedged; our drilling program including future development and drilling locations and plans, the results from our

drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; expectations

regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; future efficiencies and reserves and production growth;

anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating costs; capital spending levels in 2014 and its impact on our production

level; potential future asset impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our

future U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. taxes; future funds flow levels; future

debt and working capital levels and debt-to-funds-flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working

capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected proceeds therefrom

and production volumes associated therewith.

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

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

information including, without limitation: changes in commodity prices; changes in realized prices for Enerplus’ products; changes in the demand for or supply of Enerplus'

products; unanticipated operating results, results from development plans or production declines; changes in tax or environmental laws, royalty rates, incentive programs 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; constraints on, or unavailability of, adequate pipeline and transportation capacity;

and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F

described below and under “Risk Factors and Risk Management” in our MD&A for the year ended December 31, 2013).

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

that we will conduct our operations and achieve results of operations as anticipated; that our 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 our reserve and

resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and funds flow to fund our capital, operating

and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility

to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. We believe 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 contained in this presentation speaks only as of the date of this presentation, and none of Enerplus or its subsidiaries assume any

obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Forward Looking Information Advisory

2

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) and "Bcfe" (billion 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 Bcfes .

BOEs and Bcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at

the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly

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

barrels of oil equivalent", respectively.

Non-GAAP Measures In this presentation, we use the terms "funds flow", “free cash flow”, “capital efficiency”, and “recycle ratio” as measures to analyze operating performance, leverage and

liquidity. “Funds flow” is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation

expenditures. “Debt to funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The debt to funds flow ratio is

calculated as total debt net of cash, divided by a trailing 12 months of funds flow. “Adjusted payout patio” is used by Enerplus and is useful to investors and securities analysts in

analyzing operating performance, leverage and liquidity. We calculate our adjusted payout ratio as dividends to shareholders, net of our Stock Dividend Program (“SDP”) proceeds,

plus capital spending (including office capital) divided by funds flow. “Free cash flow” is calculated as net operating income (netback) less capital expenditures. “Capital efficiency” is

calculated as the change in production from the fourth quarter of the previous year to the fourth quarter of the current year divided by total capital expenditures from the fourth

quarter of the previous year up to and including the third quarter of the current year. A “recycle ratio” is calculated as finding and development costs divided by operating netback.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow", "capital efficiency”, and “recycle ratio” are useful

supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by

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

presented by other issuers.

Presentation of Production and Reserves Information Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under IFRS and Canadian

industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. In order to continue to be comparable with our Canadian

peer companies, the summary results contained within this presentation presents our production and BOE measures on a before royalty company interest basis. In addition, initial

test results and production performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate

recovery.

All production volumes and revenues presented herein are reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest.

Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company interest reserves" using forecast prices and

costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101)), being

3

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, 2013, includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance

with NI 51-101, is contained within our Annual Information Form for the year ended December 31, 2013 ("our AIF") which is available on our website at www.enerplus.com and

under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on

EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial statements filed on SEDAR and as part of our Form 40-F on

EDGAR concurrently with this presentation for more complete disclosure on our operations.

Discovered Petroleum Initially-In-Place Discovered Petroleum Initially-In-Place (“PIIP”) is that quantity of petroleum that is estimated to be contained in known accumulations prior to production. The recoverable portion of

discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable. Discovered Original Oil in Place (“OOIP” ) is not defined in NI 51-101 and

does not have a standardized meaning under NI 51-101. Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP for our North

Dakota assets were provided by an independent estimate by McDaniel & Associates dated June 9, 2014 and as of June 1, 2014. Discovered OOIP pertaining to our waterflood

assets are estimates by internal qualified reserves evaluators, combined for all core waterfloods.

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

resources included in this presentation pertaining to Fort Berthold and Canadian Gas-Deep Basin properties were evaluated by Enerplus and audited by independent reserve

evaluators, McDaniel & Associates. The estimates of “contingent resources” included in this presentation pertaining to the U.S. Core Gas-Marcellus were evaluated by independent

reserves evaluators, Netherland, Sewell & Associates. The estimates of “contingent resources” included in this presentation pertaining to Canadian Waterflood Assets were

evaluated by internal qualified reserves evaluators. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those

quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but

which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economics, legal, environmental,

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

project in the early evaluation stage. All of our “contingent resources” estimates are economic using established technologies and under current commodity price assumptions used

by our independent reserve evaluators. Enerplus expects to develop these “contingent resources” in the coming years however it is too early in their development for these

resources to be classified as reserves at this time. There is no certainty that we will produce any portion of the volumes currently classified as “contingent resources”. The

“contingent resources” estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered. The “contingent resources” estimate

pertaining to Fort Berthold is effective as of June 1,2014. All other “contingent resources” estimates are effective as of December 31, 2013. 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, a copy of which is available under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is

available under our EDGAR profile at www.sec.gov.

Advisories

4

Advisories

See "Non-GAAP Measures" above.

Finding & Development (“F&D”)and Finding, Development & Acquisition (“FD&A”) Costs F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs

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

F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated proved plus

probable future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs

incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs

related to its reserves additions for that year.

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

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

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

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

plus probable reserves including net acquisitions in the year. The aggregate of the exploration and development and net acquisition costs incurred in the most recent

financial year and the change during that year in estimated future development costs generally reflect total finding, development and acquisition costs related to its

reserves additions for that year.

See "Non-GAAP Measures" above.

NOTICE TO U.S. READERS The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are

not comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be

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

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

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

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

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

disclosure of oil and gas resources in SEC filings, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be

construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see “Contingent

Resource Estimates” above.

Enerplus Proven Strategy

1

Disciplined Capital

Allocation

Strong Financial Position

Sustainable, Organic

Growth & Income

• Robust, economically

grounded capital

allocation

• Capital efficiency target of

<$30,000 BOE/day

• Debt-to-funds flow ratio of

1.3x*

• $1 billion credit line

virtually unused*

• Significant hedge

positions in Q4 2014 and

2015

• Significant organic drilling

inventory

• 13% per share production

growth in 2014

• Long-term growth target of

5% ‒ 10%

• Dividend yield ~6.5%

*As at September 30, 2014.

Strong Per Share Growth

6

0.15 0.16

0.18

-

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

2012 2013 2014E*

Production/share

* Based on mid-point of revised 2014 production guidance of 103,000 BOE/day and average shares outstanding.

** Analyst consensus at October 28, 2014.

$3.29

$3.76

$4.16

-

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

2012 2013 2014E**

Funds Flow/share

BO

E p

er

Sh

are

$ P

er

Sh

are

Sustainable Growth & Dividend

7 1) Analyst consensus at October 28, 2014.

2) At November 6, 2014.

3) At September 30, 2014. Funds flow used for APO calculation is based on analyst consensus at October 28, 2014.

2012 2013 2014E

Funds Flow (MM) $645 $754 $854 (1)

Capital Expenditures (MM) $853 $681 $830

Net Acquisitions & Divestitures (MM) ($91) ($120) ($208) (2)

Dividends (MM) $302 $217 $220

SDP Proceeds (MM) ($43) ($46) ($20)

Adjusted Payout Ratio (APO) 174% 114% 120% (3)

APO, net of A&D 158% 97% 96%

D/FF ratio 1.7x 1.4x 1.3x (3)

Strong funds flow growth supporting sustainable dividend

Q3 2014 Results—Continued Performance Low-end of production guidance increased by 2,000 BOE/day

102,000 – 104,000 BOE/day annual average estimate in 2014, despite

the sale of 3,500 BOE/day of non-core divestments

Non-core divestments— two new transactions completed

3,100 BOE/day sold for proceeds of $91 million

YTD proceeds from divestments of over $200 million

Capital spending – increased as a result of net proceeds from divestments

Modest capital increase of $30 million to $830 million

Continued productivity improvements in key growth areas

Fort Berthold – YTD avg 30 day IP rate 20% above high type curve estimate

Marcellus – 25% capital efficiency improvement year-over-year

8

Funds Flow Protection

* As of Oct 22, 2014, based on weighted average price (before premiums), assuming mid-point annual average

production of 103,000 BOE/day for 2014 & 2015, less royalties of 23%.

** Include 6% (2000 bbls/day) protected at $93.64/bbl with upside participation above $94.00/bbl

*** Includes 9% (25 MMcf/day) protected at $4.17/Mcf with upside participation to $5.00/Mcf.

64%

36%

Rest of 2014

WTI Crude Oil Hedge Positions* Natural Gas Hedge Positions*

9

12%

C$4.125

38%

62%

2015

10%

11%

28%

51%

Rest of 2014

25%

3%

72%

2015

US$95.29/bbl

AECO Swaps C$4.25/Mcf

US$93.68/bbl **

NYMEX Collars

US$4.30 - $5.08/Mcf

NYMEX Swaps US$4.14/Mcf ***

NYMEX Swaps US$4.21/Mcf

Q1 NYMEX Collars US$4.53 - $5.53/Mcf

10

Core Areas

U.S.

Gas

U.S. Core Oil: Fort Berthold, North Dakota

Key Facts

Discovered OOIP 20 – 42 MMbbls/1280 DSU

Discovered OOIP (W.I.) 1.5 billion bbls

Net Acreage 73,000 acres

(114 sections)

2P Reserves at Dec 31, 2013 105 MMBOE

Best Est. Economic Contingent

Resources June 1, 2014

136 MMBOE

Future Net Drilling Locations

PUDs

Contingent Resources

330 wells

(98)

(232)

Q3 2014 Production 22,400 BOE/day

Net Locations Drilled to Date 125 wells

(93 Bakken/32 Three Forks)

11

• 2014 Focus: Productivity improvements through:

Down spacing tests

Delineation of Lower Three Forks

Completion optimization ~90% W.I.

Bakken

Three Forks

Drilling/ WOC

5

12

17

22

0

5

10

15

20

25

2011 2012 2013 2014E

MB

OE

/da

y

• 2014E annual production growth of ~30%

Fort Berthold Delivering Growth

12

• Replaced 400% of 2013 production adding 24.9 MMBOE

of reserves at F&D cost (incl. FDC) of $19.74/BOE

• Three year F&D cost of $21.56/BOE

Annual Production Reserves

0

20

40

60

80

100

2010 2011 2012 2013

MM

BO

E

Total Proved Probable

2P:

22.5

2P:

56.2

1P:

28.0

2P:

86.1

1P:

43.7

2P:

105.4

1P:

11.7

1P:

49.6

*Free cash flow is calculated as NOI less capital expenditures.

Fort Berthold: 127% Increase in Drilling Inventory

Locations

Original View

4 wells/

DSU

New View

Avg. 7 wells/

DSU

Bakken—Long 53 124

Three Forks—Long 66 89

119 213

Bakken—Short 21 63

Three Forks—Short 5 53

26 116

Total Net Future

Drilling Locations* 145 329

13

• 184 new locations added

Two thirds of locations are

long laterals

• Average 7 wells per spacing

unit with maximum of 8 wells

per unit

• Average EUR per well Long 625 Mbbls/750 MBOE

Short 320 Mbbls/385 MBOE

* Includes undeveloped reserves and contingent resources locations.

Improving Productivity through Completion Enhancements

14 14

Fort Berthold: Improving Capital Efficiencies*

15

• Reduction in well

costs and significant

increase in IP rates

driving top quartile

capital efficiencies

• On-going focus on

completion evolution

and cost improvement

* Capital efficiency based upon 30 day initial production rates

$20,500

$18,000

$15,500

$11,500 $11,000

$8,000

-

5,000

10,000

15,000

20,000

25,000

2012Ceramic:

23-29 Stages(~275 lbs/ft)

2013Ceramic:28 Stages

(~325 lbs/ft)

2013White Sand:28 Stages

(~750 lbs/ft))

2013White Sand:35-38 Stages(~750 lbs/ft)

2013White Sand:36-42 Stages(~1000 lbs/ft)

2014White Sand:36-42 Stages(~1000 lbs/ft)

Capital E

ffic

iency (

$K

/BO

E/d

ay)

16

Fort Berthold Completion Performance Improving Economics*

* Assumes US$85/bbl WTI flat crude oil price and US$4.00/Mcf NYMEX natural gas price; based on long Bakken horizontal wells.

Old Type Curve New Type Curve

High EUR Low EUR High EUR Low EUR

800 Mbbls 500 Mbbls 800 Mbbls 530 Mbbls

(950 MBOE) (600 MBOE) (950 MBOE) (635 MBOE)

30 Day Cum Prod (bbls) 23,000 15,000 43,000 31,000

1st Year Cum Prod (bbls) 155,000 98,000 243,000 165,000

NPV 10% ($MM) $11.08 $2.34 $13.76 $4.67

IRR Btax (%) 45% 15% 80% 30%

Payout (Yrs) 2.1 4.5 1.3 2.6

Recycle Ratio 3.3 2.0 3.3 2.2

Capital ($MM) 11.5 11.5 12.0 12.0

17 * Long horizontal wells only (>6,000’ lateral). Data set ~6,300 wells, at November 1, 2014.

Enerplus wells drilled without high volume completions

Enerplus wells drilled with high volume completions

volume completions

E+ Best

Bakken

E+ Best

Three Forks

Fir

st

6 C

ale

ndar

Month

Liq

uid

s P

roduction*

(bbls

)

Fort Berthold Completions Enhancements

Leading to Best in Basin Well Results

Well Count

First Six Calendar Months

18

• Core area representing almost half

of corporate liquids production

• Lower growth profile with low decline

• Primary, secondary and tertiary oil

recovery opportunities

Low Decline Canadian Waterflood Assets

Key Facts

Discovered OOIP (W.I.) 1.3 billion bbls

Recovery Factor * to Date 24%

2P Reserves at Dec 31, 2013 87 MMBOE

Best Est. Economic Contingent

Resources Dec 31, 2013

59 MMbbls

EOR & IOR

Future Net Drilling Locations 160 wells

Q3 2014 Production 20,000 BOE/day

Average Decline Rate 14%

* Estimated by internal qualified reserves evaluators. Represents the combined production for all core waterfloods divided by the

combined discovered OOIP for all core waterfloods.

Free Cash Flow from Waterflood Assets

53% 52%

41%

46%

72%

$124

$137 $179

$172

$77

$0

$50

$100

$150

$200

$250

$300

$350

2010 2011 2012 2013 2014E*

$ M

illio

n

Capital Free Cash Flow

NOI:

$266 NOI:

$272

19 * Based on September 30, 2014 forward curve and 2014 corporate differential assumptions. Free cash flow is calculated as

NOI less capital expenditures; adjusted for acquisitions and divestitures.

• Significant free cash

flow generation with

reinvestment around

55% annually

• 2014 capital higher

with Brooks program

NOI:

$287

NOI:

$301

NOI:

$320

• Concentrated, non-op

position in NE Pennsylvania

• Marcellus Q3 production

represents 52% of corporate

natural gas volumes

• 60% of core acreage held by

production

U.S. Core Gas: Marcellus

20

Key Facts

Net Acreage 53,300 acres

2P Reserves Dec 31, 2013 601 Bcf

Best Est. Economic Contingent

Resources Dec 31, 2013

1,340 Bcf

Future Net Drilling Locations 240 wells

Q3 2014 Production 187 MMcf/day

Pennsylvania

28% W.I.

Enerplus Land

Marcellus Well

Th

ickn

ess

21

41

95

-

20

40

60

80

100

120

140

160

180

200

2011 2012 2013 2014E

MM

cf/

da

y

180-200

• 2014 >90% production growth forecast

Marcellus Delivering Growth

21

Annual Production Reserves

• 2013 proved plus probable reserves increased by 168%

• 50% of corporate 2P natural gas reserves

• 2013 2P F&D of $0.58/Mcf & FD&A of $0.91/Mcf

0

100

200

300

400

500

600

2010 2011 2012 2013

Bcf o

f N

atu

ral G

as

Total Proved Probable

1P:

52

2P:

225

2P:

117

2P:

154

1P:

93

1P:

146

2P:

601

1P:

411

Marcellus: Superior Dry Gas Performance and Competitive Economics

22

Tighter stage spacing and increased proppant continues to improve performance

The 13 BCF EUR case reflects infrastructure constrained

production, with lower IP30

Differentials: 2014: -$1.35

2015: -$1.50

2016: -$1.25

2017 & beyond: -$0.50

2013 - 2014 Gross On-Streams EUR EUR EUR EUR

US$ 4.50/Mmbtu 8 Bcf 12 Bcf 13 Bcf 16 Bcf

IP30, MMcf/d 11 16 10 21

IRR, % 23 54 56 90

PV10, $MM 2.4 7.1 7.6 11.7

Capital, $MM 6.9 6.9 6.9 6.9

US$ 4.00/Mmbtu

IRR, % 13 33 35 58

PV10, $MM 0.5 4.3 4.6 8.0

Core Canadian Natural Gas—Deep Basin

• Core growth area with

approximately 450

potential net future

drilling locations in the

Wilrich and Duvernay

• 160,000 net acres of

high working interest

land

• Successful drilling

results to date in

Wilrich—moving to

development

• Advancing appraisal on

Duvernay lands

Stacked Mannville

76,000 net acres of land

(60,000 net acres of land

in the Wilrich, majority

100% WI)

Duvernay

85,000 net acres of

undeveloped land,

100% WI

23

Duvernay Shale—Willesden Green

24

R12W5 R11W5 R10W5 R9W5 R8W5 R7W5 R6W5 R5W5 R4W5 R3W5

R12W5 R11W5 R10W5 R9W5 R8W5 R7W5 R6W5 R5W5 R4W5 R3W5

Producing

Wells

Drilled Wells

Locations ENERPLUS Vt 13-7-45-

5W5M

Rig Released: 8/30/2013

Cored, logged and re-

entered

ENERPLUS Hz 1-7-45-5W5M

On production 6/2014

IP30 ~535 Boepd (30% liquids)

ENERPLUS Hz 15-8-46-9W5M

On production 10/2014

IP30 ~700 Boepd (58%

liquids)

ENERPLUS Vt 1-35-45-

10W5M

Rig Released: 10/23/2013

Cored, logged and prepped

for future re-entry

ENERPLUS Vt 11-26-45-

9W5M

Rig Released: 10/26/2012

Cored and logged

• 85,600 net acre (100% W.I.) land

• Core analysis from 4 vertical tests

supports a range of free condensate

yields across a significant portion of

acreage

• 2 horizontal wells completed and placed

on production to-date with positive results

1-7-45-5W5M average 30 day IP rate of 535

BOE per day including 2.24 MMcf per day of

sales gas with 162 barrels per day of total

liquids, 53% condensate

15-8-46-9W5M average 30 day IP rate of

700 BOE per day, including 1.75 MMcf per

day of sales gas, with 410 barrels per day of

liquids, roughly 85% condensate

• Future development at 3 - 4 wells per

section provides 300 - 400 Hz potential

drilling locations

• Continued evaluation of well results and

focus on improving well costs

Our Competitive Advantage

• Focused portfolio in top tier resource plays: Bakken/Three Forks,

Marcellus, Deep Basin & Waterfloods

• Continued focus on capital discipline—delivering 13% production/share

growth in 2014 with a target capital efficiency of <$30,000/BOE/day

• Low corporate decline rate

• Significant inventory of economic growth prospects: ~830 future

drilling locations* & sizeable upside

• Affordable growth supported by a strong balance sheet

• Delivering profitable growth with an attractive yield

25 * 2P reserves and contingent resource locations at December 31, 2013; Fort Berthold contingent resource

assessment completed June 1, 2014.

Supplemental Information

Significant Organic Growth Potential

27

Fort Berthold 16 years

Core

Waterfloods Primary Drilling

Secondary Recovery

Tertiary Recovery

Marcellus 15 years

Deep Basin (Wilrich) 10 years

* 2P reserves and economic contingent resources locations at December 31, 2013 and as at June 1, 2014 for

Fort Berthold economic contingent resources assessment. Based on current development plans.

Fort Berthold • Downspacing opportunities

Duvernay • 85,000 net acres prospective

for natural gas liquids

Torquay • Canadian Three Forks play

• 92,160 acres

144 sections

(100% W.I.)

Sleeping Giant (Montana) • Possible enhanced oil recovery

opportunity

Additional Upside:

160

Locations 330

Locations

100

Locations

240

Locations

33 40 42 44

42 42

48

59

0

10

20

30

40

50

60

70

80

90

100

2011 2012 2013 2014E*

MB

OE

/da

y

Oil & Natural Gas Liquids Natural Gas

82

90

103

Demonstrated Growth

28

Reserves** Annual Production

0

50

100

150

200

250

300

350

400

450

2010 2011 2012 2013

MM

BO

E

Liquids Crude Oil Natural Gas

49% 53% 55%

47%

43%

40% 43%

49%

47%

306 322 346

406

* Based upon mid-point of 2014 production guidance of 102,000—104,000 BOE/day.

** Proved plus probable company interest reserves at December 31.

75

Competitive Reserve Addition Costs

$26.26 $24.21

$11.28

$0

$5

$10

$15

$20

$25

$30

2011 2012 2013

$/B

OE

F&D Costs*

* Based on proved plus probable company interest reserves at December 31, including future development costs. FD&A is

defined as finding, development & acquisitions (net of dispositions).

$17.89

$22.92

$8.36

$0

$5

$10

$15

$20

$25

$30

2011 2012 2013

FD&A Costs*

$/B

OE

3 year:

$19.25 3 year:

$14.66

29

2014 Funds Flow Sensitivities

30 * The sensitivities above reflect our forecasts, outstanding commodity contracts, approximately 204.5 million

outstanding shares, and are based on forward markets as at October 22, 2014.

2014 Sensitivities

Est. effect on

2014 Funds Flow

($ Million)

Est. effect on

2014 Funds Flow per Share

($/share)

Change of $5.00/bbl WTI crude oil $5.5 $0.03

Change of $0.50/Mcf NYMEX natural gas $8.0 $ 0.04

Change of 1,000 BOE/day production for rest of year $2.5 $0.01

Change of $0.01 in the US$/CDN$ exchange rate $1.9 $0.01

Operated Light Oil Assets in the Williston Basin

Fort Berthold

Sleeping Giant

20%

80%

2013 2P Reserves*: 131 MMBOE

Fort Berthold

Sleeping Giant

31 * Company interest reserves at December 31, 2013.

20%

80%

Fort

Berthold

Sleeping Giant

(Elm Coulee)

2014E Production: 28,000 BOE/day

Dunn

Enerplus lands

Consistent Production Growth in Fort Berthold

32

• Q3 2014 production has grown 24% since the same period in 2013

• Expect to bring 5.6 net wells on-stream in Q4

14,576

15,169 18,035 18,206 18,310

20,790 22,359

25,500

-

5,000

10,000

15,000

20,000

25,000

30,000

Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 (Est)

Bo

e/d

ay

FTB Production 2013 Annual Average Production

2014E AA: 22,000 BOE/day

2013 AA: 16,500 BOE/day

Annual Average Production

Fort Berthold: 250% Increase in Contingent Resources

Original

Assumption

2014

Evaluation Increase

Discovered OOIP per DSU*

Bakken

TF1

TF2

Total

8 – 12 MMbbls

8 – 10 MMbbls

n/a

16 – 22 million bbls

8 – 16 MMbbls

10 – 16 MMbbls

2 – 20 MMbbls

20 – 42 million bbls 4 – 20 MMbbls

TOTAL WI Discovered OOIP 1 billion bbls 1.5 billion bbls 500 MMbbls

2P Reserves @ Dec. 31, 2013 105 MMBOE 105 MMBOE -

Contingent Resources

Utilization Assumptions:

Bakken

TF1

TF2

39 MMBOE

100%

70%

n/a

136 MMBOE

100%

100%

35%

97 MMBOE

33 * Per 1,280 acre drilling spacing unit (DSU).

Fort Berthold Well Density Schematic

34

6 / 7 Well Density* No Lower Three Forks Stand-Alone Locations

8 Well Density* Lower Three Forks

Productive

* Assumes 15% recovery factor.

** ”Super Unit” equivalent to lease line drilling.

TF 2 &3 Upside** TF3 & Additional

TF Wells

Fort Berthold: Increasing to Average 7 Wells/DSU

35

8

6,7,8

6 or 7

Northwest • Highest estimate of discovered OOIP

• Includes TF2

• 8 well density

Central/West • Well density ranging from 6 – 8 wells

depending upon discovered OOIP and TF2

prospectivity

Central/South • Planned for 6 or 7 well density depending

upon discovered OOIP and recovery factor

Enerplus Hognose

Successful TF2

Enerplus

Butterflies TF2

Drilling

Industry

TF2/TF3

Planned

36

Fort Berthold:

Encouraging Enerplus High Density Tests

Bakken

Three Forks

Drilling/ WOC

Snakes Pad

8 Well Density & TF2

Enerplus down spacing test

(7 well density)

Enerplus down spacing test &

TF2 test

Fur Bearers pad

7 Well Density Fur Bearers Pad

Snakes Pad

Months on Production

Cum

. O

il (M

bbls

)

200

250

300

50

2 6 8

TF1

4 10

100

Butterflies/Turtles* pad

8 Well Density & TF2

Enerplus down spacing test &

TF2 test

* Butterflies/Turtles pad on-stream early November

Fort Berthold Completion Evolution Increasing Production Rates

37

Completion Costs/Stage

• Despite larger fracs, the

switch to sand and

effective cost

management has helped

reduce completion costs

• Significant increase in

30 day cumulative

production from high

intensity fracs

US

$K

$319

$241

$215 $195

$221 $216

$-

$50

$100

$150

$200

$250

$300

$350

Oil

(Mbbls

)

30 Day Cum. Oil BKN TF

21 22 22

34

40

60

18 20

-

27 32

45

-

10

20

30

40

50

60

70

# Wells: 17 Bkn / 6 TF 3 Bkn / 1 TF 2 Bkn / 0 TF 2 Bkn / 2 TF 6 Bkn / 3 TF 2 Bkn / 3 TF

38 * Long horizontal wells only (>6,000’ lateral). Data set ~7,000 wells, at November 1, 2014.

Enerplus wells drilled without high volume completions

Enerplus wells drilled with high volume completions

volume completions

E+ Best Bakken

E+ Best Three Forks

Peak C

ale

ndar

Month

Cum

ula

tive P

roduction*

(bbls

)

Fort Berthold Completions Enhancements

Leading to Best in Basin Well Results

Well Count

Peak Calendar Month

Fort Berthold U.S. Crude Marketing

• ~540,000 bbls/day of regional pipe capacity currently

available and another 200,000 bbls/day coming into

service after 2016

• Rail loading capacity is plentiful with > 1.2 MMbbls

available at more than 16 unit train facilities

• Current take-away capacity exceeds regional production

by 60%

• Enerplus seeks to maintain a balanced approach to

marketing commitments

13,500 bbls/day of firm regional egress commitments

currently in place

5,000 bbls/day firm commitment made to Sandpiper

project to Clearbrook expected in late 2017 or early

2018

39

Rail 69%

Pipe 31%

Available Capacity

* Refers to August 2014 North Dakota and Montana production of ~1.2 MMbbls per NDIC and Montana Board of Oil

and Gas Conservation reports.

Fort Berthold: Natural Gas and NGL Production

40

87%

7%

6%

Fort Berthold (Q3 2014 BOE/day)

Oil Gas Liquids

• Gas and NGLs are gathered and marketed

by our gatherer at market netback pricing

• Realized natural gas price is higher than

NYMEX because of higher heat content

• Enerplus has been proactively focused on

gas conservation

~80% of our wells are connected to gas

gathering; increasing by year-end

All wells are being equipped with high

efficiency flares as back-up in case of

disruptions

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

Jan-1

2

Ma

r-1

2

Ma

y-1

2

Jul-1

2

Sep-1

2

No

v-1

2

Jan-1

3

Ma

r-1

3

Ma

y-1

3

Jul-1

3

Sep-1

3

No

v-1

3

Jan-1

4

Ma

r-1

4

Ma

y-1

4

Jul-1

4

Sep-1

4Realized Gas Price

Ft. Berthold(1300 BTU factor)

Nymex

US

$/M

cf

Brooks Overview

41

S

S

S

S

S

S

S

31 3231 32 33 34 35 3631 32 33 34 35 3632 33 34 35 36

56

7 8

1718

19 20

2930

31 32

123456

7 8 9 10 11 12

131415161718

19 20 21 22 23 24

252627282930

31 32 33 34 35 36

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7 8 9 10 11 12

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19 20 21 22 23 24

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31 32 33 34 35 36

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8 9 10 11 12

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20 21 22 23 24

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7 8 9 10 11 12

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7 8

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7 8 9 10 11 12

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19 20 21 22 23 24

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8 9 10 11 12

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32 33 34 35 36

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7 8

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7 8 9 10 11 12

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R11W4R12R13R14

R11W4R12R13R14

T16

T17

T18

T19

T20

T16

T17

T18

T19

T20

North

Key Facts

Discovered OOIP 223 MMbbl

Recovery Factor to Date 27%

2P Reserves at Dec 31, 2013 9 MMBOE

Best Estimate Contingent Resource

Dec 31, 2013

1.7 MMBOE

Cumulative Oil Production to Date 61 MMbbl

2014E Production 2,750 BOE/day

Average Base Decline Rate 12%

South

• Lower Mannville/Basal Quartz (~1,000 m depth)

• Potential to drill 60 locations over the next two+

years

• Currently running two rigs in Brooks South

• Early production performance has been positive

with average results in-line with our type-curve

expectations 100% Working Interest

79 88 83

131

179

189 187

-

50

100

150

200

250

300

Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 (Est)

MM

cf/

da

y

Total Marcellus Production Annual Average Production

Marcellus Production Growth

42

2013 AA: 95 MMcf/day

2014E AA: 190 MMcf/day

190

Marcellus Well Cost & Performance Evolution

43

$10,000

$8,000 $7,000

0

2,000

4,000

6,000

8,000

10,000

12,000

2012 2013 2014

$ T

housands

Total Well Cost

-

2

4

6

8

10

12

2012 2013 2014

IP30

IP60

IP90

*

Initial Production

MM

cf/

day

$7,500

$5,500

$4,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2012 2013 2014

$/B

OE

/day

30 Day Capital Efficiency

* 2014 production rates include curtailment.

TGP Z4 300

Spot: 34%

Transco Leidy

Spot:

22% Dominion

South:

36%

Transco Z6

NNY:

3%

Remainder priced at:

TETCO M3 (NY), TGP 500

(Tennessee) and TGP Z4

200 (Ohio)

Marcellus Sales Price Mix – Q3 2014

* Map Source: Kinder Morgan. 44

• Regional firm, must-take

contracts of ~80 MMcf/day

plus ~10 MMcf/day of

pipeline capacity out of the

region held through 2015,

with remainder sold at spot

market

• Executed sales and

precedent transportation

agreements for up to 80

MMcf/day at Transco Non-

New York to backfill our

must-take contracts starting

in 2016

Northeast U.S. Pipeline Projects: >8 Bcf of Projects Planned

45

Project Pipeline Owner Incremental Takeaway

(MMcf/day)

Destination In Service

Rose Lake 300 TGP KM 230 NE* Q4 2014

Transco - Northeast Connector Transco Williams 100 NE Q4 2014

Transco - Rockaway Lateral Transco Williams 647 NE Q12015

Columbia East Side Expansion TCO Columbia 300 NE Q3 2015

Niagara Expansion TGP KM 158 Canada Q4 2015

Northern Access 2015 NF Nat Fuel 140 Canada Q4 2015

Transco - Leidy Southeast Transco Williams 525 Southeast Q4 2015

Constitution Constitution Williams 650 NE/Canada Q1 2016

Rock Springs Lateral Transco Williams 192 NE Q3 2016

Algonquin Incremental Market (AIM) Algonquin Spectra 342 NE Q4 2016

Connecticut Expansion TGP KM 72 NE Q4 2016

Northern Access 2016 NF National Fuel 250 Canada Q4 2016

Atlantic Sunrise Transco Williams 1,700 Southeast Q3 2017

Atlantic Bridge Algonquin Spectra 100 NE Q4 2017

Susquehanna West Expansion TGP KM 145 NE Q4 2017

Penn East Project PennEast

Pipeline UGI, SJR, NJR, AGL 800 NJ/Non NY Q4 2017

Northeast Energy Direct (NED) TGP KM 800 NE Q4 2018

Diamond East Transco Williams 1,000 NJ/Non NY Q4 2018

330

1,123

2,745

1,800

1,506

* Internal sources, November 2014

Northeast Pa. Marcellus Pipeline

Infrastructure Future Takeaway Capacity

• Production growth could be

capped at 1.5 Bcf/day based

on the pace of expected

pipeline additions in the

NE Pa. Marcellus

• Could see basis relief by

2017/2018 as capacity

additions appear to be

sufficient to meet this pace of

production growth

46

Source: ERF estimates (as of Sep 2014)

Key Facts

Key properties Edson, Ansell, Minehead,

Hanlan

Net Acreage (acres) 60,000 acres

(92 sections, majority 100% WI)

2P Reserves Dec 31, 2013 62 Bcfe

Best Est. Economic Contingent

Resources Dec 31, 2013

253 Bcfe

Future Net Hz Drilling Locations >100 wells

Est. EUR/Well 5.0–7.0 Bcfe

Q3 2014 Stacked Mannville

Production

27 MMcf/day

Contiguous land blocks in highly prospective regions

Canadian Gas—Deep Basin (Wilrich)

47

• Growth potential to 60+ MMcf/day

• Ownership in existing infrastructure to support up to

50 MMcf/day

Ansell – CORE FOCUS

Q4 2014 capital acceleration

- 3-well Wilrich pad

development

North Ansell – CORE FOCUS

- Finishing 2-well pad in

Q4 2014 with partners.

Completion and tie-in Q1

2015

Wilrich Activity

48

Assumptions:

Capital: $7MM/well; assumes pad drilling

Liquids: 7-10 bbls/MMcf

AECO $4.00/Mcf

EUR

7 Bcf

EUR

6 Bcf

EUR

5 Bcf

NPV10 ($MM) $6.7 $5.3 $3.9

IRR (%) 46 38 30

Payout (years) 2.0 2.4 2.8

IP30 (Mcf/day) 7,600 6,900 6,200

BESC ($/Mcf) $2.23 $2.42 $2.65

AECO $3.50/Mcf

NPV10 ($MM) $5.2 $4.0 $2.7

IRR (%) 36 29 23

Payout (years) 2.5 2.9 3.5

• Operated activity for Q4 2014 Commencement of three-well

pad in Ansell

• Non-operated activity Two-well pad in North Ansell

• rig release in Q4 2014

with expected on-stream

Q2 2015

• Results from both programs will

be evaluated for additional 2015

activity

Debt Composition at September 30, 2014

Senior Notes* US$966MM CDN$70MM

Bank Facility $58MM

Unused Capacity $942MM

*Canadian dollar equivalent of U.S. dollar denominated notes FX rate at September 30, 2014 US/CDN of 1.1208.

• Bank Credit Facility - $1 billion

• 11 banks in Enerplus’ bank credit facility

• Unsecured, covenant-based with current

borrowing rate of less than 3%

• Credit facility matures October 31, 2017

• Senior Unsecured Notes - CDN$1,036 MM

• Notes are rated NAIC 2 and rank equally

with bank credit facility; average interest

rate of 5.3%

• On September 3, 2014 we closed a

US$200 million private placement of senior

unsecured notes with a 10 year average

life at an interest rate of 3.79%

49

Senior Notes Maturities

$12

$97

$0

$51 $51

$80

$130 $130

$147

$124 $124

$45 $45

$0

$20

$40

$60

$80

$100

$120

$140

$160

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

$ M

illi

on

s

50

Average interest rate of 5.3%*

* US$ amounts converted at US/CDN 1.1208.

Enerplus Share Ownership

As of October 20, 2014

Investor Composition Geographic Composition

Total Retail

60% Total Institutional

40%

51

36%

24%

20%

21%

US & Other Retail Canadian Retail

US & Other Institutional Canadian Institutional

56%

44%

United States & Other Canada

Enerplus Board of Directors

Elliott Pew, Chairman of the Board(1)(2)

Mr. Pew, Chairman of Enerplus, is a co-founder of Common Resources and served as its Chief Operating Officer until the company was sold in May, 2010. He is

currently a Director for the newly formed Common Resources II located in The Woodlands, Texas. Previously, Mr. Pew was Executive Vice President -

Exploration at Newfield Exploration Company in Houston where he led Newfield’s diversification efforts onshore in the late 1990’s in addition to leading the

company’s exploration program, including the formation of the deep water GOM business unit. Prior to Newfield, Mr. Pew was Senior Vice President - Exploration

with American Exploration Corp. Mr. Pew is a Geology graduate of Franklin and Marshall College and holds an M.A. in Geology from the University of Texas.

David H. Barr, Director (12)

Mr. Barr has 38 years of experience in the oil and gas industry, and is President and Chief Executive Officer of Logan International Inc., a company focused on

downhole tools and completion services. He was formerly Chairman of the Board of Logan International. He also spent close to 36 years with Baker Hughes in

various executive roles, including Group President of numerous divisions and President of Baker Atlas. He currently serves as a Director of ION Geophysical

Corporation and Probe Technology Services. Mr. Barr holds a B.S. Mechanical Engineering degree from Texas Tech University.

Michael Culbert, Director (3)(9)

Mr. Culbert brings over thirty years of diverse experience in the oil and gas industry in North America and is currently the President, Chief Executive Officer and a

Director of Progress Energy Canada Ltd. He brings a strong background in business development, economics and strategic planning and holds a Bachelor of

Science degree in Business Administration. He currently sits on the Board of Directors of Pacific NorthWest LNG Ltd. and is also a member of the Canadian

Association of Petroleum Producers’ Board of Governors.

Edwin V. Dodge, Director (9)(11)

Mr. Dodge is currently a corporate director following a 35-year career with Canadian Pacific Railway Limited ("CPR", a Canadian national rail carrier), where he

was Chief Operating Officer from 2001 until his retirement in March 2004. Prior to 2001, Mr. Dodge held other senior roles with CPR including Executive Vice

President of Operations for Canada and the U.S., as well as Chief Executive Officer of a Minneapolis-based railroad. Mr. Dodge holds a Civil Engineering degree

and an MBA from the University of Western Ontario.

Ian C. Dundas, Director

Mr. Dundas became President and Chief Executive Officer of Enerplus on July 1, 2013. He joined the company in 2002 as Vice-President of Business

Development, with accountability for all corporate acquisition and divestment strategies. In 2010, his role expanded to that of Executive Vice-President. In 2011,

his responsibilities were further expanded to include the role of Chief Operating Officer, overseeing the development and execution of the company’s operational

strategies, strategic planning, marketing, reserves, as well as acquisitions and divestments. As President and Chief Executive Officer, Mr. Dundas is responsible

for overall leadership of the strategic and operational performance of Enerplus.

Enerplus Board of Directors continued

Hilary Foulkes, Director (5)(11)

Ms. Foulkes has more than 30 years of experience within the Canadian oil and gas industry focused in the areas of exploration, development and investment

banking. She has held executive roles in both investment banking and oil and gas operations, including Executive Vice-President and Chief Operating Officer for

Penn West Petroleum Ltd. She is a professional geologist and earned a Bachelor of Science (Honours, Earth Sciences) from the University of Waterloo. Her

career highlights include being the architect and lead negotiator of award-winning, multi-billion dollar international joint ventures.

James B. Fraser, Director (7)(11)

Mr. Fraser has over 35 years of energy industry experience, and was the Senior Vice President for the shale division of Talisman Energy Inc.'s North American

operations. From 2006 to 2008, Mr. Fraser was Vice President of operations for the southern division of Chesapeake Energy and prior to this spent over 20 years

at Burlington Resources and its predecessor companies, where he held a number of senior positions including North American Exploration Manager. Mr. Fraser

holds a MBA from Regis College and a Bachelor of Science in Petroleum Engineering from the Montana School of Mines.

Robert B. Hodgins, Director (3)(6)

Mr. Hodgins has been an independent businessman since November 2004. Prior to that, Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy

Trust (a TSX and NYSE-listed energy trust) from 2002 to 2004. Prior to that, Mr. Hodgins held the position of Vice President and Treasurer of Canadian Pacific

Limited (a diversified energy, transportation and hotels company) from 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited (a TSX

and NYSE-listed energy transportation company) from 1993 to 1998. Mr. Hodgins received a Bachelor of Arts in Business from the Richard Ivey School of

Business at the University of Western Ontario in 1975 and received a Chartered Accountant designation and was admitted as a member of the Institute of

Chartered Accountants of Ontario in 1977 and Alberta in 1991.

Susan M. MacKenzie, Director (7)(10)

Ms. MacKenzie has over 25 years of energy sector experience, most recently serving as Chief Operating Officer with Oilsands Quest Inc. in 2010. Prior to that,

Ms. Mackenzie enjoyed a 12-year career at Petro-Canada where she held senior roles including Vice-President of Human Resources and Vice President of In

Situ Development & Operations. Ms. MacKenzie was also with Amoco Canada for 14 years in a variety of engineering and leadership roles in natural gas,

conventional oil and heavy oil exploitation. Ms. MacKenzie holds a Bachelor of Engineering (Mechanical) degree from McGill University, an MBA from the

University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA).

Donald J. Nelson, Director (3)(9)

Mr. Nelson has over 40 years of experience in the oil and gas industry, and is the president of Fairway Resources Inc., a private consulting services firm. Prior to

this, Mr. Nelson was with Summit Resources from 1996 to 2002, until its acquisition by Paramount Resources Ltd., where he held the position of Vice President

Operations from 1996 to 1998 and President and Chief Executive Officer from 1998 to 2002. He currently serves as Director for Perpetual Energy Inc., Keyera

Corp., as well as three other private companies. Mr. Nelson is a Professional Engineer, a member of the Association of Professional Engineers, Geologists and

Geophysicists of Alberta and of the Society of Petroleum Engineers.

Enerplus Board of Directors continued

Glen D. Roane, Director (4)(5)

Mr. Roane is a corporate director and currently serves as a director of Enerplus, Badger Daylighting Ltd., Logan International Inc., SilverBirch Energy Corporation

and the GBC American Growth Fund. Mr. Roane is also a member of the Alberta Securities Commission. Previously he served as a board member of many TSX-

listed companies and private companies including Repap Enterprises Inc., Ranchero Energy Inc., Forte Resources Inc., Valiant Energy Inc., Maxx Petroleum Ltd.,

UTS Energy Corporation, Destiny Resource Services Ltd., NQL Energy Services Inc., Severo Energy Ltd., Flexpipe Systems Inc., and Tarpon Energy Services

Ltd. Mr. Roane retired from TD Asset Management Inc., a subsidiary of The Toronto-Dominion Bank in 1997. Previously he was a founding partner of Lancaster

Financial Inc., a financial advisory and investment management firm and was formerly employed by Burns Fry Limited and by the Toronto Dominion Bank. Mr.

Roane holds a Bachelor of Arts (1977) and an MBA (1979) from Queen's University in Kingston, Ontario and holds the ICD.D designation from the Institute of

Corporate Directors.

Sheldon B. Steeves, Director (5)(8)

Mr. Steeves has over 37 years of experience in the North American oil and gas industry and is currently a Director of Tamarack Valley Energy Ltd., a Canadian oil

and gas company with operations in the Western Canadian sedimentary basin. From January 2001 until April 2012, Mr. Steeves was Chairman and CEO of

Echoex Ltd., a junior private company focused on greenfield organic growth in Western Canada. Mr. Steeves spent over 15 years at Renaissance Energy where

he was appointed Chief Operating Officer in 1997. He holds a Bachelor of Science in Geology from the University of Calgary.

(1) Chairman of the Board

(2) Ex-Officio member of all Committees of the Board

(3) Member of the Corporate Governance & Nominating Committee

(4) Chair of the Corporate Governance & Nominating Committee

(5) Member of the Audit & Risk Management Committee

(6) Chair of the Audit & Risk Management Committee

(7) Member of the Reserves Committee

(8) Chair of the Reserves Committee

(9) Member of the Compensation & Human Resources Committee

(10) Chair of the Compensation & Human Resources Committee

(11) Member of the Safety & Social Responsibility Committee

(12) Chair of the Safety & Social Responsibility Committee

Investor Relations Contacts

Jo-Anne M. Caza

Vice-President, Corporate & Investor Relations

403-298-2273

jcaza@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

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