68. RETAILTexasmarketingpresentationFINAL.pdf - Enerplus

The Game Plan
Enerplus Corporation – Investor Update
April 2011

Enerplus Overview
• High-yielding North American energy producer
• Focused on providing both growth and income to
investors
• Diversified asset base of high quality, low decline oil
and gas assets complemented by growth assets in
resource plays with superior economics - Bakken
crude oil and Marcellus shale gas
• Cash flow from operations and strong financial position
support capital reinvestment and monthly dividend
Monthly
dividend
plus growth
potential
• Strong internal technical and commercial expertise
• Converted from income trust to dividend paying
corporation on Jan 1, 2011
1

Corporate Profile
• Trading Symbol (TSX/NYSE) ERF
• Market Capitalization (1) $5.2 billion
• Enterprise Value (2) $5.9 billion
• Average Daily Trading Value (Q1 2011) $45 million
• 2011E Average Daily Production 78,000 – 80,000 BOE/day
• 2011E Exit Production 80,000 – 84,000 BOE/day
– Oil and Liquids Weighting 47%
• 2011E Development Capital Spending $650 million
• Long-Term Debt /Trailing 12-Month Cash Flow Ratio (3) 1.0x
• Current Monthly Cash Dividend $0.18/share
• Current Annualized Yield (at April 19, 2011) 7.3%
1.Market Cap. at April 19, 2011 – based upon shares outstanding at December 31, 2010
2.Market Cap. at April 19, 2011 plus outstanding debt (net of cash) at December 31, 2010
3.Using outstanding debt and Cash Flow from Operations at December 31, 2010
2

Dividend Philosophy
• Imposes capital discipline and appropriate pace of
development
• Demand for yield supported by demographics,
Enerplus’ current investor base and low interest
rate environment
• Excess cash flow in future years expected to be
disproportionately allocated to reinvestment in
assets
We will
continue to
share our cash
flow with
investors
• Current ~7% yield
3

Significant Portfolio Repositioning
Added over
500,000 net new
acres of
undeveloped
land
Non-core
dispositions have
funded new
growth
acquisitions
• Our goal was to improve the focus and profitability
of our portfolio
• Build core growth areas that would have scope and
scale:
• Bakken Crude Oil:
• ~230,000 net acres in ND and SK
• Marcellus Shale Gas:
• ~200,000 net acres in PA, WV and MD
• Deep Basin:
• 80,000 net acres in AB & BC
• Complement the foundation assets that generate
free cash
• Sale of non-core assets has helped to improve
operating performance and fund acquisitions of new
growth assets
4

Our Assets
Tight Gas/Shallow Gas
• Capital Spending:
• $60 MM tight gas
• $10 MM shallow gas
• 39% of production
• 19% of NOI
• 542 Bcfe 2P reserves
2010 Divestments
• Sold 10,400 BOE/day non-core assets
• $870 MM in proceeds
• 115 properties
• Average netback $28/BOE
• Op cost $14/BOE
• 2P reserves – 34 MMBOE (69% oil)
Crude Oil Waterfloods
• $110 MM capital spending
• 18% of production
• 28% of NOI
• 84 MMBOE 2P Reserves
• 60 MMBOE Best Estimate
Contingent Resource
Bakken/Tight Oil
• $300 MM capital spending
• 20% of production
• 36% of NOI
• 58 MMBOE 2P Reserves
• 60 MMBOE Best Estimate
Contingent Resource
Marcellus Shale Gas
• $160 MM capital spending
• 5% of production
• 3% of NOI
• 117 Bcfe 2P Reserves
• 3.9 Tcfe Best Estimate Contingent
Resource
Based on 2011 outlook. Remaining percentages attributed to other conventional oil and gas properties
5

2010 Year-End Reserves Summary
P+P Reserves
Oil
Properties
(MMBOE)
Gas
Properties
(Bcfe)
Total
(MMBOE)
Opening
Balance 171.8 1,039 344.9
Production (12.7) (105.4) (30.3)
Divestments (23.4) (63.9) (34.0)
Acquisitions 11 4.8 11.8
Additions 16.8 107.3 34.7
Revisions (2.6) (108.5) (20.7)
Closing
Balance 161.4 868.9 306.2
• Majority of decline in 2010 due to
dispositions
• Development capital delivering
results
• All-in $17.46/BOE F&D before
revisions
• $10.74/BOE F&D at Ft Berthold
• $1.64/Mcfe F&D at Marcellus
• Revisions primarily in shallow gas
properties
• 40% of revisions due to price
decline
• Performance revisions at
Shackleton ~ $100 MM PV10%
- 2% of year-end NPV
6

Current Reserves Breakdown
53% Oil and NGL’s
• Over 50% of reserves are
from key resource plays
MMBOE
350
300
250
200
150
100
50
0
306.2 MMBOE
P+P Reserves
19%
27%
6%
18%
12%
18%
2010
Bakken
Waterfloods
Marcellus
Tight Gas
Shallow Gas
Other Oil & Gas
• Oil weighting is now 53% of
total reserves
• PDP reserves - 62%
• Proved reserves - 72%
• Conservative booked future
locations - 313 net locations
across portfolio
• Bakken reserves have
increased by 42% in last two
years
• Shallow gas reserves now
have significantly lower
corporate weighting
7

Added Meaningful Upside Potential
Crude
Oil
Natural
Gas
P+P
Reserves
0.9 Tcf
P+P
Reserves
161
MMBOE
* See disclaimer for disclosure on Contingent Resources.
Company Interest reserves as at December 31, 2010.
Best Estimate
Contingent
Resources*
120 MMBOE
Best Estimate
Contingent Resources*
3.9 Tcf
• Marcellus, North Dakota Bakken
and waterflood contingent
resource is 3.5x current P+P
reserves
• Significant future opportunity
captured in best estimates of
contingent resources:
• ND Bakken: 60 MMBOE,
90 future drilling locations
• Waterflood: 60 MMBOE
• Marcellus: 3.9 Tcf, 926
future drilling locations
• We also believe there is further
potential in our Bakken,
Waterflood and Deep Basin
lands
8

We Can Deliver Growth
• Portfolio has mature, stable cash generating assets
complemented by key growth opportunities
• $1.3 billion in capital spending over next 2 years
• Production growth of 10 - 15%
• 5% debt-adjusted growth in 2012
• Cash flow growth of 15% by end of 2012
• Capital increases by 20% to $650 million in 2011
• 2011 capital spending focused on oil projects
Production
growth of
10 – 15% over
next two-year
period
• 85% of spending on Bakken, Waterfloods and Marcellus
• Similar level of spending in 2012
• Beyond 2012, expect 5% debt-adjusted growth per year
9

2011 Capital Focus
Resource Play
Capital
($MM)
#
of Net
Wells
2010 Exit
Production
(MBOE/day)
2011E
Exit Production
(MBOE/day)
Change
Exit to Exit IRR** BESC**
Bakken/Tight Oil 300 48 13.3 18 – 21 35 – 55% >40% $40 – 55/bbl
Waterfloods 110 26 13.8 13 – 15 0 – 10% >30% $60/bbl
Marcellus Shale Gas 160 27 2.9 7 – 8 140 – 170% 10 – 30% $3.50 – 4.50/Mcf
Sub-Total $570 101 30 38.5 – 44 30 – 45%
Company Total* $650 113 77.2 80 – 84 5 – 10%
Over 90% of drilling is horizontal wells
* Includes spending on Shallow Gas ($10 MM), Tight Gas ($60 MM) and Other Conventional Oil & Gas ($10 MM)
** Using February 14, 2011 forward prices. Marcellus economics are based on 4, 5 and 6 Bcf type wells assuming a $4.50/MMBtu gas price
BESC – Breakeven supply cost providing a 12% rate of return
10

Production Outlook
MMBOE/day
100
90
80
70
Bakken
60
Marcellus
50
Waterfloods
40
30
20
Rest of Portfolio
10
0
Exit 2010 Exit 2011 Exit 2012
43% Liquids 47% Liquids 49% Liquids
Growing Oil
• Increase in oil weighting results
in approaching an even split
between gas and liquids
• Oil production is +80%
weighted to light/medium
grades
Decline Profile
• Higher decline in growth plays
increases corporate decline
over next several years before
stabilizing
• 2010 exit corporate decline at
19%
• increasing 2% - 4% per
year
11

Financial Outlook
900
800
Oil
Gas
Adjusted Payout Ratio
Cash Flow Estimates
180%
160%
• 2011 and 2012 cash flow is
approximately 70%
weighted to liquids, up from
approximately 65% in 2010
700
600
140%
120%
• Balance sheet supports
growth plans through 2012
$ Millions
500
400
300
200
100
0
2010 2011 2012
100%
80%
60%
40%
20%
0%
• Payout ratios decline as
production from growth
plays increases
• Non-cash flow generating
asset sales expected to
help maintain financial
flexibility
Adjusted Payout Ratio = (Capex+Dividends)/Cash Flow
Based upon the forward commodity prices (WTI US$98/bbl, AECO $3.85/Mcf, NYMEX Gas US$4.50/MMBtu) and
forecast costs as of February 14, 2011 including the impact of hedging
12

Managing the Balance Sheet
Debt to Cash Flow Ratio
2.5x
2.0x
1.5x
1.0x
0.5x
0.0x
1.0x
2.0x
Exit 2010 2012
Potential Funding Sources
• Equity portfolio interests with
book value of ~$150 million
• Laricina – 4.3 million shares
• Non-core conventional and oil
sands acreage
• YTD sold non-cash generating
interests for ~$60 million
• Marcellus
• Possibly reduce a portion of
our interests
13

Crude
Oil

U.S. Bakken
Regional Overview
Enerplus: Sleeping Giant
Enerplus: Ft Berthold
Source: RSEG, Oct. 2010
15

Bakken & Three Forks Geology
Middle Bakken
Upper Three Forks
Geological Age Mississippian Devonian
Depth 10,500 – 11,000 ft 10,600 – 11,000 ft
Thickness 35 – 45 ft 30 – 45 ft
Porosity 5 - 6% 6 - 10%
Overpressure 0.6 – 0.8 psi/ft 0.6 – 0.8 psi/ft
OOIP/640 acres 4 - 6 MMbbls 4 - 5 MMbbls
• Believe all our acreage is prospective for
dual development
• Industry testing Three Forks proximal to
our leasehold:
• Helis Oil and Gas Dodge well offsetting
our acreage to the west - produced 90
Mbbls in 4 months
Source: Tudor Pickering Holt & Co.
• Kodiak well offsetting our acreage to the
east - 24 hour IP rate of 1,042 BOE/day;
30 day average of 603 BOE/day - only 6
of 22 stages currently completed
16

Fort Berthold Reserves vs. Contingent Resource
MMBOE
70
60
50
40
30
20
10
22.4
Almost 3x P+P
reserve upside
60
• 22.4 MMBOE P+P reserves
• 24 booked drilling locations
• Less than 1 year’s drilling
locations
• 60 MMBOE of “best estimate”
contingent resource from the
Bakken only
• 90 future drilling locations
• 65% long laterals
• 85% land utilization
• ~15% recovery factor
0
P+P Reserves
Contingent Resource
Best Estimate
• Incremental upside from the
Three Forks and downspacing
17

Fort Berthold, North Dakota
Key Facts
Net Acreage
Current Production
P+P Reserves (Dec. 31, 2010)
Contingent Resource Est. (Best)
74,500 (116 sections)
~4,000 BOE/day
22.4 million BOE
60 million BOE
• Bakken & Three Forks potential
• Long lease tenure, concentrated
acreage position
• 42° API, light sweet crude oil
• High netback production ~$50/bbl
• Production growth to over 20,000
BOE/day over next 4 years
>90% operated & ~90% working interest
18

Fort Berthold Bakken Results to Date
Long Laterals
(9,000 ft. 24 frac stages)
Type
Curve
Actual
4 Well avg
Short Laterals
(4,500 ft. 12 frac stages)
Type
Curve
Actual
5 Well avg
Average 30 day initial production (bbls/day) 1,100 – 1,200 1,250 550 – 650 730
Expected Ultimate Recovery (Mbbls) 600 – 800 300 – 400
Cost/Well ($/MM) $8.5 $8.5 $6.0 $6.0
120 day Cumulative Production (bbls) 81,000 100,000 40,000 59,000
Expected Net Present Value (12%, $MM)* $11.2 - $18.0 $3.9 – $7.4
Expected Netback* ($/bbl) ~$50 ~$50
Expected Payout Period (years) 1.3 – 0.8 2.2 – 1.3
Expected F&D ($/BOE) $13.00 - $9.75 $18.50 - $13.50
*Based on February 14, 2011 forward price
Royalties average 20%, plus state production tax of 11.5%, op costs of $4/bbl, Differential assumption of $10 - $12/bbl
19

Fort Berthold Results
Long laterals are 35% ahead of the average type well prediction
Short laterals are 45% ahead of the average type well prediction
160,000
Barrels
140,000
120,000
100,000
Actual Short Bakken Laterals (5 Wells)
Actual Long Bakken Laterals (4 Wells)
Cumulative Short Type Well
Cumulative Long Type Well
80,000
60,000
40,000
20,000
-
0 30 60 90 120 150 180
Days Producing
20

2011 Fort Berthold Bakken Plans
• 2011 capital program - $230 million
• 32 net operated wells, 75% long horizontals
• Targeting Bakken primarily; 3 to 8 Three Forks wells
planned
• 3 to 4 rigs working in the play
• Recently entered into agreements to secure frac
services, proppant and a rig to help ensure timely
execution of plans
• Expect to have midstream service agreements in place in
mid-2011 to capture associated gas and liquids
Production
grows from
4,000 bbls/day to
+20,000 BOE/day
over next 4 years
21

Significant Future Production Growth from Fort Berthold
Manageable growth, self-funding in 1 – 2 years
30,000
25,000
20,000
Production assuming 4 rigs
Incremental production - 4 to 6 rigs
Capital required - 4 rigs
Incremental capital required - 4 to 6 rigs
Free Cash Flow (NOI - Capex) - 4 rigs
Free Cash Flow (NOI - Capex) - 4 to 6 rigs
$600
$500
$400
• Growth potential of
20,000 – 25,000 BOE/day
by 2014
• Over $1 billion of capital
over next 4 years
BOE/day
15,000
10,000
$300
$200
$ Millions
• Net operating income
approaches ~$500 million
by 2014
5,000
0
2011 2012 2013 2014
$100
$0
• Expected F&D cost of
$11 - $16/BOE
-5,000
-$100
Assumes February 14, 2011 strip pricing
22

U.S. Bakken Infrastructure Capacity
Barrels
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
Pipe
Capacity
Shortfall
Plains Bakken Proposal
Keystone XL Market Link
Belle Fourche Proposal
Enbridge Bakken
125k
80k
Enbridge North Dakota
Butte Pipeline
50k
100k
60k
93k
186k
150k
• Current U.S. Bakken
production is ~400
MBOE/day
• 500 MBOE/day in 2011
• Pipeline capacity shortfall:
• 80 MBOE/day in 2010
• could increase to 125
MBOE/day in 2011
• Rail and trucking covers
capacity shortfall
Mandan Refinery
55k
0
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Source: Internal company data and industry analysis
• Numerous new pipelines and expansions of over 300 MBOE/day are proposed to
address the takeaway shortfall
• We control some pipeline capacity and also sell to intermediaries who hold capacity on
existing pipelines or who have access to trucking/railing facilities
23

Waterfloods
Key Facts
OOIP
P+P Reserves (Dec 31, 2010)
Best Est. Contingent Resources
~1.3 billion BOE
83.7 MMBOE
(booked to 27%)
60.5 MMBOE
Recovery to date 21%
Average Oil Quality
2011E Annual Production
30° API
13.5 – 15.0 MBOE/day
18% of company total
Low decline, predictable base production
• Free cash flow supports dividend and growth
strategy
• ~50% of operating income reinvested into
waterflood assets
• Production expected to decline at ~10% before
capital additions in 2011
• 2010 additions of 3.5 MMBOE (plus 0.6 MMBOE
positive revisions)
24

Waterflood Reserves vs. Contingent Resource Upside
90
80
70
60
Over 70% upside to P+P reserves
60.5
• 83.7 MMBOE P+P reserves
• 45 booked drilling locations
• No reserves booked associated
with EOR pilots
MMBOE
50
40
83.7
EOR
34.3
• 60.5 MMBOE of “best estimate”
contingent resource assessed on a
portion of our waterflood properties
30
20
10
0
P+P Reserves
Dec 31, 2010
IOR
26.2
"Best Estimate"
Contingent Resource
• EOR contingent resource included
only at 2 properties where projects
underway
• Further upside potential exists under
both IOR and EOR scenarios
25

Waterflood Development Plans
• 2011 Plans - $110 million
• Drilling 26 wells, advancing polymer
pilots
• Reviewing all major waterflood
properties for enhanced recoveries
using new drilling technologies and
EOR opportunities
• Mature fields require facilities
upgrades to support future production
• ~$50 million on facilities in 2010
• ~$40 million budgeted for 2011
• Over 30% IRR on 2011 capital
program
• 2011E op costs of $14.50/BOE with
NOI of over $40.00/BOE based on
current commodity prices
Invest to maintain production while
setting up future opportunity
Key Properties
2011
Capital
Budget
($MM)
Play
Medicine Hat Glauc C, AB $24 Glauconitic
Freda Ratcliffe, SK $18 Ratcliffe
Virden/Daly, MB $13 Lodgepole
Giltedge, AB $9 Lloydminster
Gleneath, AB $9 Viking
Pembina 5-Way, AB $4 Cardium
Joarcam, AB $3 Viking
Other $30 Various
26

Natural
Gas

Marcellus Shale Gas Overview
• Current land position of
~ 200,000 net acres
• 70,000 net operated acres with an
average working interest of 90%
• Long lease tenure at attractive
entry price in area that has
good thickness & maturity
• Average 24% non-operated working
interest in ~467,000 gross acres
(~114,000 net) primarily in
Pennsylvania and West Virginia with
Chief Oil & Gas
• Average 19% non-operated working
interest in ~103,000 gross acres
(~20,000 net) in NE Pennsylvania
with EXCO Resources
28

Marcellus Potential
Planned
production
growth of over
150 MMcf/day
over next 4
years
Contingent Resource Est. 2009 2010
Operated - 1.2 Tcfe
Non-Operated 2.1 Tcfe 2.7 Tcfe
Total 2.1 Tcfe 3.9 Tcfe
# of Net Locations 639 926
Land Utilization 55% 65%
Average EUR/Well 3.4 Bcfe average 4.2 Bcfe average
Well Costs $4 – $5 million $4.5 – $6.8 million
Density 4-8 wells/640 acres 4-8 wells/640 acres
2P Reserves 24 Bcfe 117 Bcfe
3.9 Tcfe of
best estimate
contingent
resource
• Majority of reserve bookings are in Lycoming, Susquehanna
and Marshall counties - represents about 1 year’s drilling
• Best estimate of contingent resource is nearly 5x booked
corporate 2P natural gas reserves
• Attractive finding and development costs of $1.64/Mcfe in 2010
and over life
29

Marcellus Performance – Cumulative Production
Type curve estimates have been increased as well
results have either met or exceeded our expectations
25% of wells are above 6 Bcfe type curve
1,400,000
6.0 Bcfe Type Curve
1,200,000
3.5 Bcfe Type Curve
Cumulative Production (Mcfe)
1,000,000
800,000
600,000
400,000
Top 5 wells with 180 days of production
Average Actual Production
200,000
0
0 30 60 90 120 150 180 210 240 270 300 330 360
Days Producing
30

Marcellus Well Economics
80%
NYMEX
$/MMbtu
IRR
4.0 Bcf Well 5.0 Bcf Well 6.0 Bcf Well
Payout
(Years)
NPV 12%
($MM)
IRR
Payout
(Years)
NPV 12%
($MM)
IRR
Payout
(Years)
NPV 12%
($MM)
* Assumes long-run
well cost of $6.0 MM
$6.00 27% 3.4 $2.51 41% 2.5 $4.57 57% 2.0 $6.62
60%
$5.00 16% 4.9 $0.75 26% 3.4 $2.37 37% 2.6 $3.99
$4.00 7% 8.6 ($1.02) 13% 5.7 $0.17 20% 4.2 $1.35
BTAX IRR
40%
• Wells in the liquids rich gas window of the Marcellus
that have higher liquids content show a ~20%
improvement in netbacks versus dry gas wells
6.0 Bcf Type Curve
20%
3.5 Bcf Type Curve
0%
$3 $4 $5 $6
NYMEX Gas ($US/MMBtu)
31

Marcellus Drilling Activity To Date*
Gross Wells Drilled (at Mar 3, 2011) Horizontal Vertical Total
Producing 42 9 51
Partially Drilled** 4 1 5
Waiting on Completion 33 5 38
Waiting on Pipeline 11 6 17
Total Gross Wells 90 21 111
* Includes operated and non-op wells drilled by Chief & Exco
**Vertical portion of well drilled, awaiting horizontal extension
• Current plans show drilling activity in 12 counties in PA, as well as Marshall and
Preston counties in West Virginia
• Majority of producing wells in Bradford, Lycoming and Susquehanna Counties in NE
PA (>80% of current production) and Marshall County in WV
• Current net production is ~20 MMcfe/day
32

2011 Marcellus Plans
• 2011 capital program of $160 million
• 150 gross wells planned (22.4 net)
• Operated : 5 gross wells, 1 rig
• Non-Operated: 145 gross wells, 8 - 10 rigs
• Expect to complete ~121 gross wells with 94 new
gross wells on stream by the end of the year
• Capital:
• 25% directed to liquids rich gas in SW PA and NW
WV
• 30% directed to delineation activity to preserve
lease positions and identify future potential
• 45% of capital directed to development drilling in
areas with EUR’s of 4.5 to 5.5 Bcf
• May see upward pressure on capital due to
activity levels
• Current average netback ~$2.50/Mcfe
Production
growth of
150% in
2011
33

Future Production Growth in the Marcellus (unconstrained)
Full scale development not planned. Sizeable resource capture provides
opportunity for material development even with partial interest reduction
MMcfe/day
350
300
250
200
150
100
50
0
-50
-100
-150
-200
Production
Capital
Free Cash Flow (NOI - Capex)
2011 2012 2013 2014
$1,200
$1,000
$800
$600
$400
$200
$0
-$200
-$400
-$600
$ Millions
• Under full scale development
(unconstrained), production
grows to 350 MMcfe/day by
end of 2014
• Over $2.4 billion of capital
over next 4 years
• Net operating income grows
to over $500 million by 2014
• Expected F&D cost of
~$1.60/Mcf
-250
-$800
Assumes February 14, 2011 strip pricing
34

Marcellus Water Access & Handling
• ERF and our JV partners have sufficient
water source permits to execute
development plans
• ERF and our JV partners are permitting and
constructing additional water impoundments
• ERF developing centralized water
infrastructure with gas gathering system
(Centre County, PA)
• Implemented closed loop system for drilling
fluids management in 2010
• Goal to recycle 100% of produced and flow
back water by end of 2011
• Chief building a centralized tank farm for
storage and recycling
• ERF reusing flow back fluid on location to
reduce fresh water use
• JV partners utilizing industrial water
treatment plants and disposal wells for
water disposal
35

Long-Term Strategy for Enerplus
• Balanced portfolio of oil and gas assets
• Focus on both mature properties and early stage
growth plays to manage corporate decline rates and
ensure disciplined capital investment
• Build concentrated positions in core areas to deliver
top quartile results and be the “best” operator
• Continue to opportunistically pursue strategic
acquisition - no plans to sell further cash generating
assets at this time
Provide
sustained total
return of
10% – 15%
per year to
shareholders
• Balance sheet can support our plans
• Continue to unlock the value from our foundation
assets
36

Supplemental Information
The Game Plan

2011 Guidance
Summary of 2011 Expectations Target Comments
Average annual production
78,000 - 80,000 BOE/day
Exit rate 2011 production 80,000 - 84,000 BOE/day Assumes $650 million development
capital spending
2011 production mix 53% gas, 47% liquids
Average royalty rate 20% Percentage of gross sales (net of
transportation costs)
Operating costs
$9.20/BOE
G&A costs $3.30/BOE Includes non-cash charges of
$0.30/BOE (stock option plan) and
$0.20/BOE impact of the new IFRS
rules
Average interest and financing costs 6% Based on current fixed rate contracts
and forward interest rates
Development capital spending $650 million Within the context of current commodity
prices
Marcellus carry commitment spending $116 million Will be reported as a property
acquisition
38

2011 Annual Production Outlook
BOE/day
86,000
84,000
82,000
80,000
78,000
76,000
74,000
72,000
2011 Production Profile
Range of production
Capital Allocation:
• 65% to growth plays
• 35% to foundation assets
• Capital spend evenly
weighted throughout the year
• Longer cycle times at Fort
Berthold and Marcellus influencing
production build throughout year
70,000
Q1 Q2 Q3 Q4
39

Cash Flow Sensitivity
The sensitivities below reflect all commodity contracts and forward markets as at February 14,
2011. To the extent the market price of crude oil and natural gas change significantly from
current levels, the sensitivities will no longer be relevant as the effect of our commodity
contracts will change.
Sensitivity Table
Estimated Effect on 2011
Cash Flow per Share (1)
Change of $0.50 per Mcf in the price of AECO natural gas $0.18
Change of US$5.00 per barrel in the price of WTI crude oil $0.09
Change of 1,000 BOE/day in production $0.08
Change of $0.01 in the US$/CDN$ exchange rate $0.06
Change of 1% in interest rate $0.03
(1)
Assumes 178,939,000 shares outstanding.
The impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the
impact of any inter-relationship among the factors.
40

Hedging
The following is a summary of the financial contracts in place at February 14, 2011
expressed as a percentage of our forecasted net production volumes:
Natural Gas
(CDN$/Mcf)
January 1, 2011
– March 31, 2011
January 1, 2011
– December 31, 2011
Crude Oil
(US$/bbl)
January 1, 2012
– December 31, 2012
Sold Puts (limiting downside protection) $4.15 $56.50 -
% of forecasted 2011 net production 26% 11% -
Swaps (fixed price) $6.39 $87.27 $94.60
% of forecasted 2011 net production 33% 58% 20%
Purchased Calls (repurchasing upside) $6.48 $ 101.17 -
% of forecasted 2011 net production 26% 11% -
41

Reserves and Contingent Resources
Play Types
Proved
Proved plus
Probable
Reserves
Proved plus
Probable
Booked
Net Drilling
Locations
“Best
Estimate”
Contingent
Resources
Future
Contingent
Resource
Drilling
locations
Bakken/Tight Oil (MMBOE) 38.0 57.5 39 60* 90
Crude Oil Waterfloods (MMBOE) 65.2 83.7 45 60** n/a
Other Conventional Oil (MMBOE) 20.8 27.7 23 - -
Total Oil (MMBOE) 124.0 168.9 107 120 90
Marcellus Shale Gas (Bcfe) 52.4 117.2 13 3,904 926
Tight Gas (Bcfe) 228.7 320.8 40 - -
Shallow Gas (Bcfe) 164.8 220.5 152 - -
Other Conventional Gas (Bcfe) 126.3 165.0 1 - -
Total Gas (Bcfe) 572.1 823.5 206 3,904 926
Total Company (MMBOE) 219.4 306.2 313 771 1,016
* Bakken at Fort Berthold only – excludes Three Forks upside
** Includes both IOR and EOR opportunities which could include future drilling locations only on a portion of our waterflood portfolio
42

Portfolio Transition Activity
Acquisitions
Dispositions
Net Acreage
Production
Cost
($ Million)
Marcellus Non-Operated Acreage 128,500 acres $448
Marcellus Operated Acreage 70,200 acres $185
North Dakota Bakken 74,500 acres $618
Saskatchewan Bakken 140,000 acres $176
Deep Basin 65,000 acres $40
Total 478,200 acres $1,467
Proceeds
($ Million)
Non-Core Conventional Assets ~10,600 BOE/day ~$600
Kirby Oil Sands - $405
Joslyn Oil Sands - $500
Total Proceeds ~$1,505
43

Enerplus Ownership
Canadian
US & Foreign
Institutional
Retail
30%
25%
70%
75%
10-24
STAGES
6-10
STAGES
6-7
STAGES
As of February 2011
Reported 13-F positions
as of December 31, 2010
44

$1 Billion Credit Facility
Canadian Imperial Bank of Commerce $145
Royal Bank of Canada $120
Bank of Montreal $120
Bank of Nova Scotia $110
Toronto Dominion Bank $100
National Bank of Canada $85
Alberta Treasury Branches $50
Total Canadian
$730 million
HSBC Bank $85
Citibank N.A. $85
Union Bank of California $50
Sumitomo Mitsui Bank $50
Total Foreign
$270 million
45

Long-Term Debt
($ thousands) December 31, 2010 December 31, 2009
Current portion of long-term debt * $- $36,631
Long-term:
Bank credit facility 234,713 -
Senior notes:
CDN$40 million (Issued June 18, 2009) 40,000 40,000
US$40 million (Issued June 18, 2009) 39,784 41,864
US$225 million (Issued June 18, 2009) 223,785 235,485
US$54 million (Issued October 1, 2003)* 53,709 56,516
US$175 million (Issued June 19, 2002)* 140,414 148,411
732,405 522,276
Total debt $732,405 $558,907
* Principal repayments due in 2011 under these notes have not been included in current liabilities as
Enerplus intends to refinance the amounts with our long-term bank credit facility.
46

Supplemental
Bakken
Information

Fort Berthold Development Plans
B
1280 acres
TF B TF
1320’ 1320’ 1320’
• Maximize long horizontals
• Develop from pads: 2 Bakken/2 Three Forks
• Tie in as soon as possible
• Test inter-well spacing
• Work with other operators to time development
• Reduce cycle time to 45 days from rig release
of final well on pad to production
• Implement salt water disposal solution
• Understand and successfully implement
simultaneous operations
TF B B TF
1280 acres
• Drilling and completion of additional wells
on producing pads
48

Fort Berthold Well Timeline
10 – 12 months
Well application / permit
approval
Site Build
Drilling
Waiting on Frac
Crews
Fracing
4-6 months
1 month
1 month /well
2 months
1-2 weeks
• Environmental assessment
required on all federal lands
• Have 11 permits in hand or very
late stage approval
• Completing EA process on
additional 30 permits - expect
approval between April and June
• 50 permits are underway for
submittal between now and
August
• Expect 40 additional permits
submitted by year-end
• Cannot
begin
building site
until permit
in hand
• Multi-well
pads
• “walking
rig” will help
reduce
drilling time
• Shortage
of basinwide
fleets
relative to
drilling
activity
49

Fort Berthold Well Costs
Long Laterals
Short Laterals
Drilling
$2.8 MM
Completion
$5.7 MM
Drilling
$2.4 MM
Completion
$3.3 MM
Total Cost $8.5 MM
Total Cost $5.7 MM
Completions - 125,000 lbs of proppant/stage, $1.3 - $1.5 MM for ceramic proppant
- Water: 2,500 – 3,000 bbls/stage, $3 - 6/bbl for trucking & disposal fees
Tie-in - Additional $500,000
Expect pad drilling will materially decrease tie-in costs
50

Fort Berthold Execution Capability
• 4 rigs under contract
• 2 active at present; 2 moving in
March / April, conditions permitting
• Upgrading process
• 2 “walkers” focused on pad drilling
• Expect to sign at least one
incremental rig by September
• Frac services:
• Multi-year frac services agreement
signed – should keep pace with 3 –
4 rig program
• Plan to drill 40 – 50 wells/year from
2012 – 2016 to fully develop acreage
(Bakken and Three Forks)
51

Fort Berthold Production - Gathering
• Enerplus has committed to a field gathering system at the Fort Berthold
Reservation which will:
• Aggregate production at a central collection point off the Reservation that will
provide flexible options for marketing the barrels
• Gather and monetize both gas and liquids at market prices
• Reduce the potential for shut in production due to varying weather, road
conditions, and availability of trucking contractors
• Provide some ability to better manage and dispose of produced water
• Reduce the number of trucks moving on the Reservation which will reduce
dust and road wear, and increase safety for the residents
52

Fort Berthold Production – Enerplus Regional Transportation
Current Transportation / Sales Arrangements in Place for
Fort Berthold Development
'000 ‘000 bbls bbls/day / day
25
25
20
20
15
10
10
5
5
0
0
2011 2012 2013 2014
2011 2012 2013 2014
Middle Pace (6 Rigs)
Basic 4 Rig Program
3rd Party Sales / Transport
Enbridge Bakken Expansion
Belle Fourche Reversal
Four Bears Pipeline
Historic Enbridge Capacity
Enerplus has the flexibility to use its Enbridge North Dakota Pipeline capacity for its
Sleeping Giant (Elm Coulee) production as well.
53

Supplemental
Waterflood
Information

The Stages of Oil Recovery
Stage
Waterflood
• Injecting high pressure water
Implications
• Hold production steady, grow recovery
• Facilities in place
• Maintenance costs increasing with age
Improved Oil Recovery (IOR)
• Optimizing waterfloods through
sweep, pattern or voidage
improvements
• Conducting lab work to screen for
EOR potential
Enhanced Oil Recovery (EOR)
• Reducing residual oil saturation
and improving sweep efficiency
• Grow production & recovery
• Spending capital up front for future benefit
• Expand facilities
• Convert vertical producers to injection
• Drill horizontal producers
• Maintenance costs improved
• Grow production and recovery
• Spending capital up front for future benefit
• Increasing op costs
• Facilities for polymer injection
• Polymer
55

Polymer Flood
• Polymer is chemical additive
that increases viscosity of
injected water
• Reduces residual oil saturation
• Improves sweep efficiency
• Works best with heavier crudes
in high permeability reservoirs
with low waterflood recovery
factors
• The first identified projects are
at Giltedge and Medicine Hat
Glauc C
• Typical expected recovery
improvement is ~8 - 15% (rule
of thumb is 30% of the projected
waterflood recoverable oil)
Source – Oil and Gas Journal
56

Giltedge – Polymer EOR Project Area
Key Facts
Area of
Polymer
Project
26
36
25
22 23 24
14 13
Wildmere Unit (4.73% WI)
Wildmere Unit
E+ 4.7% WI
OOIP
Recovery Factor to Date ~13%
Cumulative Production
P+P Reserves (Dec 31, 2010)
Best Est. Contingent Resource
Oil Quality
2011E Avg. Production
126 MMBOE
16.4 MMBOE
10.4 MMBOE
(booked to 21%)
16.6 MMBOE
14° - 20° API
1,700 BOE/day
oil, 97% water cut
• Waterflood initiated in 1974, we acquired in
1996
11
12 12
• Lloydminster zone at a depth of 650 metres
• Historical decline: ~13%
100 % Working Interest
• Expected 2011 netback: ~$45/BOE
• IOR and EOR contingent resource potential of
16.6 MMBOE, over 60% more than current 2P
reserves
• Polymer project underway in 2011
57

Dec-14
Dec-13
Dec-12
Dec-11
Dec-10
Giltedge Production History
Production maintained for last decade
3000
2500
2000
1500
1000
58
Total Pool Base and Incremental
from Polymer project (BOE/day)
500
Pool Base Production (BOE/day)
0
Reconstruction
Downtime
Oil Production (BOE/day)
Dec-94
Dec-95
Dec-96
Dec-97
Dec-98
Dec-99
Dec-00
Dec-01
Dec-02
Dec-03
Dec-04
Dec-05
Dec-06
Dec-07
Dec-08
Dec-09

Giltedge – Anticipated Polymer Upside
Polymer Project
Area
• Potential incremental
reserve adds of 0.8 –
1.5 MMBOE in project area
• Production in project area
could increase 2 - 3 times
from current levels over
next
20 - 30 months
• Full field internal best
estimate contingent
resource of 13 MMBOE
(10% incremental RF)
Polymer injection wells
59

Giltedge – Polymer Project Costs and Economics
Material value creation opportunity
• Project timeline
• Q2 2011 – first injection, production response in ~6 months
• Polymer injection will continue for approximately four years
• Decision to expand may be made sometime after 2013
• Intent is to be at full field polymer flood by late 2017
Project costs
• Facilities - $7 million
• Polymer - $10 million (over 4 years)
• Operating Cost - $1 million/year
• Indicative economic factors
• NPV @ 10%: ~$20 million
• IRR: 25 - 40%
60

Medicine Hat Glauc C – Polymer Potential
Key Facts
OOIP
217 MMBOE
Recovery Factor to Date ~8%
Cumulative Production 17 MMBOE
P+P Reserves (Dec 31,
2010)
Best Estimate Contingent
Resource
Oil Quality
2011E Avg. Production
16.5 MMBOE (booked to 15%)
IOR 6.5 MMBOE (+3% RF)
EOR 21.7 MMBOE (+10% RF)
11° to 18° API
2,500 BOE/day, 91% water cut
72% WI across ~14 sections
• Discovered in 1984, acquired in 1998, unitized
in 2001
• Glauconitic ‘C’ zone at 825 metre depth
• Initiated waterflood in 2001 with focused
development from 2007
• Currently 112 producing and 55 injection wells
• Aggressive facilities optimization program over
past 2 years has reduced op costs from
$12.50/BOE to below $10.00/BOE
61

Medicine Hat Glauc C – Production History
3500
Average Daily Production (BOE/day)
3000
2500
2000
Drilled 7 wells/5 injector
conversions and expanded 2
batteries
1500
1000
62

Medicine Hat Glauc C – EOR Potential
EOR could more than double
remaining reserves
• EOR design complete by mid 2011
• First polymer project begins in Q2 2012 with a second project starting
one year later
• Estimated incremental recovery factor of 10%
• 21.7 MMBOE of best estimate contingent resource under polymer flood
63

2011 Development Capital Plans at Med Hat
EOR Project $2 million:
Facilities $10 million:
Wells $12 million:
Total Budget - $24 million:
• Early costs including
design, skids, etc.
• Battery expansions
and rebuilds – Q2
2011 completion
• Fluid handling
optimization ongoing
• Decrease HZ well
spacing to 100
metres
• Drill source well
west of river
• Optimized production
and injection
• Increase EUR by 3%
(6.5 MMBOE)
• Anticipated full cycle
F&D of ~ $20/BOE
64

Freda/Skinner/Neptune, SK - Ratcliffe & Bakken
• Approximately 115,000 net
acres of Ratcliffe rights
• Majority overlay Bakken rights
• Oungre/Ratcliffe zones at a
1,600 - 1,800 metre depth
• Current Ratcliffe production
~1,700 BOE/day
• Internal best estimate
contingent resource of 9.0
MMBOE, 70% of our booked
2P reserves
Enerplus Ratcliffe
Rights
Average working interest > 98%
Ranging from 70 –100%
• Current reserves are booked to
26%
• Bakken results to date
disappointing – further analysis
required
• Positive success in the Ratcliffe
65

Freda Lake Ratcliffe Unit
Freda Lake Ratcliffe Voluntary Unit #1
99.86% WI
Key Facts
OOIP
55 MMBOE
Recovery Factor to Date ~14%
Cumulative Production
P+P Reserves (Dec. 31, 2010)
8 MMBOE
10.2 MMBOE
(booked to 31%)
Best Est. Contingent Resource 2.3 MMBOE (+4%
RF)
Oil Quality
2011E Exit Production
32° API
1,900 BOE/day oil
(+40% vs 2010)
Enerplus Ratcliffe Rights
2009/10 Development Locations
2011 Development Locations
2011 Injector Conversions
Horizontal wells and waterflood optimization
unlocked major resource
• Discovered 1967 & developed on 80 acre vertical well
spacing, acquired in 2003
• Peripheral waterflood implemented mid 1980’s
• New wells attract lower royalties
• Historical decline ~ 4%, RLI ~40 years
• Injection conversions increasing oil production from
surrounding producers
• Recent single and dual leg HZ wells producing at
150-300 bbl/day with 37-65% water cuts vs a
previous pool average of over 90%
66

Freda Lake Ratcliffe Unit Production
2,500
2,000
Up to 14 more HZ wells to drill in the unit
Verticals & Horizontals - Oil
Rate
Vertical Wells Only - Oil Rate
Expected Production
Oil Production (BOE/day)
1,500
1,000
Water Injector Conversions
Increased Production
~ 100 BOPD Before HZ
7 HZ wells drilled increased
production from ~500 BOE/day to
over 1,300 BOE/day at year-end
500
4% Historical Decline
0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
67

Supplemental
Marcellus
Information

Marcellus Performance – NE Pennsylvania
21 MARCELLUS
HORIZONTAL PRODUCERS
Daily Production (Mcf/day)
14,000
12,000
10,000
8,000
6,000
4,000
Lycoming 1 Lycoming 2
Lycoming 4 Lycoming 3
Lycoming 10 Lycoming 11
Lycoming 12 Lycoming 13
Lycoming 14 Lycoming 5
Lycoming 6 Lycoming 7
Lycoming 8 Lycoming 9
Susq. 1 Susq. 2
Susq. 3 Lycoming 15
Lycoming 16 Lycoming 17
Lycoming 18
Average Horizontal
Type Curve (EUR 6 BCF)
2,000
0
0 60 120 180 240 300 360 420 480 540 600 660 720 780 840
Days on Production
69

Marcellus Well Design
• Drilling (Average 30 days)
• Operated
• Drilling primarily delineation wells – with vertical pilot, cores and logs
• 5 single well pads in Centre County, PA (2 wells ) and Preston County, WV (3
wells)
• Lateral length of 4,000’ to 5,000’
• Closed loop system with synthetic mud
• Installing water infrastructure
• Non – operated
• Drilling primarily lease saving operations, rather than pad drilling
• Vast majority single well pads with a few 2 to 4 well pads
• Longer laterals 3,000’- 5,000’
• Closed loop system with synthetic mud
• Completions (2 to 4 weeks)
• Operated
• 10 – 12 frac stages, 300’ to 400’ per stage
• 4 perf clusters per stage
• Slickwater frac with multiple sweeps
• Non-operated
• Fewer frac stages and larger frac intervals 400’ – 450’
• 6 – 9 perf clusters per stage
• Still testing 1 month “resting” of wells
• Reduced chemical loading
Drilling costs
range from
$2.5 – $3.5
million
Completion
costs range
from $3.0 –
$4.0 million
70

Marcellus Well Timeline
6 – 8 months
Well application / permit
approval
Site Build
Drilling
Waiting on Frac
Crews
Fracing
45 – 60 days in PA
45 – 90 days
25 – 35
days/well
30 - 60 days
7 - 14 days
• 30 – 45 days in WV
• Assumes water sources
permitted
• Current regulations
• Cannot begin
building site
until permit in
hand
• Depends on
time of year
• Multi-well
pads
• “self-skidding”
rigs help
reduce drilling
time
• Shortage of
frac fleets
relative to
basin-wide
drilling activity
Note: Timeline excludes well “resting” and tie-in to gathering systems
71

Gathering Gas in the Marcellus
NE PA
Susquehanna, Bradford,
Sullivan, Lycoming
Central PA
Clearfield,
Clinton, Centre
Midstream Party Chief Midstream Caiman/ Chief
Midstream
South PA
Cambria, Somerset,
Fayette
SW PA & WV
Marshall,
Green PA
Caiman Caiman /
MarkWest Plant
Comments
Most mature area of the
field where Chief has
been acquiring ROW
and laying pipe to their
own producing wells for
the past 2 years
New drills are
just being
evaluated and
egress routes
being
investigated
Pipeline activity
wasn’t started until
2010 as no wells
were completed
(assume 1 year
behind Marshall
County)
Liquids rich gas
area that is
currently flowing
wet into the sales
pipe waiting on
the MW Plant for
liquids extraction
Wells to be tied-in
in 2011
30 - 35 6 - 20 25 - 32 25 - 30
72

Moving Natural Gas Out of the Marcellus
• Enerplus has taken several steps to ensure we can move our growing
Marcellus gas production to market:
• Entered into longer term (5 years +) firm “must take” contracts with creditworthy
substantial end users of the natural gas who:
• hold firm capacity on the various interstate pipelines (Transco, Tennessee)
• have storage capacity and trading ability
• These contracts have flexibility to increase delivered volumes as we bring
production to pipe:
MMBtu/d 2011 2012 2013 2014 2015
Min Max Min Max Min Max Min Max Min Max
Committed Sales into Transco Pipeline: 12 36 48 74 68 81 65 80 38 45
Committed Sales in to Tennessee Gas Pipeline: 21 30 30 38 14 38 38 14 6 6
• Participated in the Wyoming Pipeline Project that creates optionality for our
production between the two key pipelines - Transco and Tennessee
• Entered into a firm processing and marketing agreement with MarkWest for our
liquids rich gas produced in Marshall County
73

Supplemental
Deep Basin
Information

Deep Basin Opportunity
Stacked Mannville
Potential
• 60,000 net acres of land
(42,000 undeveloped)
Deep Basin growth opportunities
Existing Enerplus assets
Montney Potential
• 20,000 net acres of
undeveloped land
• Approximately 80,000 net
acres of high working interest
land throughout the region
• Includes 100% working
interest in approximately
60,000 undeveloped acres
• Multiple contiguous acreage
blocks with liquids rich multizone
potential
• In 2011, focused on
delineating the resource given
price environment
Large, long tenure, high working
interest land holdings
75

Stacked Mannville
Key Facts
Key properties
Net Acreage (acres)
Pine Creek to Hanlan
~60,000 total (42,000 undeveloped)
Future HZ Drilling Locations 100 - 200
Expected EUR/Well*
2.8 - 4.0 Bcfe
• Acquiring and utilizing 3D seismic
• Drilled/drilling 3 delineation wells, 3 others
licensed and ready to execute in 2011
• Liquids ratios of 15 – 40 bbls/MMcf
• Additional de-risking ongoing by competitors
and partners
Contiguous land blocks in highly
prospective regions
Enerplus working interest lands
* Expected EUR/well based on public data from offset wells. Number of future locations based on development of
30% to 60% of Enerplus acreage
76

Stacked Mannville Geology
• Stacked cretaceous horizons
provide vertical risk mitigation
and multiple horizontal targets
• Cardium
• Notikewin
• Wilrich
• Bluesky
• Gething
• Cadomin
* Indicative geologic section
77

Stacked Mannville Type Curve Economics
Target
Raw gas
recovered
AECO
($/Mcf)
IRR%
Cadomin + 1 up hole
completion
Bluesky or Wilrich
2.8 Bcf Well 4.0 Bcf Well
Payout
(Years)
NPV
12%
($MM)
IRR%
Payout
(Years)
NPV
12%
($MM)
$6.00 30 2.6 $2.4 74 1.4 $6.2
$5.00 19 3.4 $1.0 53 1.8 $4.6
$4.00 8 5.3 ($0.5) 34 2.4 $2.6
Capital $7.0 million $6.0 million
30 Day IP 3,700 Mcf/day 3,900 Mcf/day
Liquids 18 bbls/MMcf 15 bbls/MMcf
Type curves are internal estimates based on local analogue/competitor information
February 14, 2011 forward commodity price outlook
78

Montney
b-66-B well
Pink Mountain
Mntn Licenses
Key Facts
94-G-2
Mntn Production
ERF Well License
Key Properties Cameron /
Julienne Creek
ERF 3D Seismic
Net Acreage (acres) 17,000
Future Hz Drilling Locations 50 – 150
Enerplus
Expected EUR/Well
3.5 – 5.5 Bcfe
• 3D seismic purchased and
reprocessed
94-B-15
• Existing well (b-66B) indicates over
300 metres of Montney thickness
• Rock analysis indicates good
reservoir development
• Liquids ratio is expected to be
between 20 and 30 bbls/MMcf
• Enerplus well licensed in Q1 2011
although drill timing is uncertain
100% working interest
79

Montney Type Curve Economics
AECO
($/Mcf)
IRR
%
3.5 Bcf Well 4.5 Bcf Well 5.5 Bcf Well
Payout
(Years)
NPV
12%
($MM)
IRR
%
Payout
(Years)
NPV
12%
($MM)
IRR
%
Payout
(Years)
$6.00 27 2.7 2.1 45 1.8 3.9 64 1.4 5.7
$5.00 18 3.9 0.8 30 2.4 2.4 44 1.8 4.0
$4.00 10 6.5 -0.4 19 3.8 1.0 28 2.6 2.3
NPV
12%
($MM)
Capital $6.2 million $6.2 million $6.2 million
30 Day IP 3,800 Mcf/day 4,000 Mcf/day 4,000 Mcf/day
Liquids 20 bbls/MMcf 20 bbls/MMcf 20 bbls/MMcf
BESC $4.30/Mcf $3.37/Mcf $2.80/Mcf
• Type curves are based on Town Montney
• Capital assumes pad drilling
• February 14, 2011 forward commodity price outlook
80

Deep Basin Development Plan
• Pace of development heavily influenced by natural gas prices
• High working interest and 3+ years of land tenure allow us to control the
pace of play on our undeveloped land position
• Shorter-term focus on delineation versus development with a view to
future gas price recovery
• Benefiting from competitor de-risking
• 2011 Capital spending plans:
• $38 million
• Mix of operated and non-operated activity
• 3D seismic
81

Disclaimers
Assumptions
All economics contained have been calculated using forward prices and costs as of February 14, 2011. 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. "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, 2010, which will include complete disclosure of our oil and gas reserves and other oil and gas information in
accordance with NI 51-101, will be contained within our Annual Information Form for the year ended December 31, 2010 ("our AIF") which is available on our
website at www.enerplus.com and on our SEDAR profile at www.sedar.com. Additionally, our Annual Information Form is part of our Form 40-F that has been
filed with the U.S. Securities and Exchange Commission and will 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 for more complete disclosure on our operations.
Contingent Resource Estimates
This presentation contain 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 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." 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, 2010. 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.
82

Disclaimers
For information regarding the primary contingencies which currently prevent the classification of our disclosed “contingent resources” associated with our Marcellus
shale gas assets as reserves and the positive and negative factors relevant to the “contingent resource” estimate, see our Annual Information Form for the year
ended December 31, 2009 (and corresponding Form 40-F) dated March 12, 2010, a copy of which is available on our SEDAR profile at www.sedar.com and a
copy of the Form 40-F which is available on our EDGAR profile at www.sec.gov. With respect to the “contingent resource” estimate for our North Dakota Bakken
properties, the primary contingencies which currently prevent the classification of our disclosed “contingent resources” associated with the properties as "reserves"
consist of additional delineation drilling to establish economic productivity in the development areas and limitations to development based on adverse topography
or other surface restrictions. Significant positive factors related to the estimate include; continued advancement of drilling and completion technology and early
performance of producing wells that are above forecast. A significant negative factor related to the estimate is the limited performance history in the immediate
area of the “contingent resource”. With respect to our Waterflood assets, the primary contingencies which currently prevent the classification of our disclosed
“contingent resources” associated with the properties as "reserves" are due to the early stage of implementation to the specific patterns within the existing
waterfloods and the early stage of the specific enhanced oil recovery projects to the existing waterfloods. Significant positive factors related to the estimate include
established waterflood technology, the history of waterflood performance data and the estimates are based on incremental recovery from higher displacement
efficiency only with no improved recovery from additional areal sweep. A significant negative factor relevant to this estimate is the geological complexity and its
effect on injector producer connectivity. There are a number of inherent risks and contingencies associated with the development of our interests in these
properties including commodity price fluctuations, project costs, our ability to make the necessary capital expenditures to develop the properties, reliance on our
industry partners in project development, acquisitions, funding and provisions of services and those other risks and contingencies described above, and that apply
generally to oil and gas operations as described above, and under "Risk Factors" in our Annual Information Form referred to above.
F&D Costs
F&D costs presented 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.
Non-GAAP Measures
In these presentations, we use the terms "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the term "F&D
costs" as a measure of operating performance. We calculate "payout ratio" by dividing cash distributions to unitholders by cash flow from operating activities, both
of which are measures prescribed by Canadian generally accepted accounting principles ("GAAP") and which appear on our consolidated statements of cash flow.
"Adjusted payout ratio" is calculated as cash distributions to unitholders plus development capital and office expenditures, divided by cash flow from operating
activities. We also use the term "netback", which is used to measure operating performance and is calculated by subtracting Enerplus’ expected royalties and
operating costs from the anticipated revenues in respect of the relevant properties. Enerplus believes that, in addition to net earnings and other measures
prescribed by GAAP, the terms "payout ratio", "adjusted payout ratio", "F&D costs" and "netback" 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.
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Disclaimers
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained herein 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 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.
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