32
FirstEnergy/Societe Generale East Coast Energy Conference March 2012
The Game Plan
FirstEnergy/Societe Generale
East Coast Energy Conference
March 2012
1
Corporate Profile
• Enterprise Value (1) $5.4 billion
• Average Daily Trading Value (Q4 2011) $46 million
• 2012 Average Daily Production Guidance 83,000 BOE/day
• 2012 Exit Production Guidance 88,000 BOE/day
– Oil and Liquids Weighting 50%
• 2012 Development Capital Spending Guidance $800 million
• Current Monthly Cash Dividend $0.18/share
• Current Annualized Yield (at Feb. 23, 2012) 8.8%
1. Market Cap. at Feb. 23, 2012 plus Dec 31, 2011 net debt of $900 million less net proceeds from Feb. 8, 2012 equity issue of $330 million.
Enerplus Strategy
• North American E&P company with a diversified portfolio of crude
oil and natural gas properties that have development opportunities
for near-term and future growth
• Capture new resources in high margin regions at a reasonable
price to build future growth potential
• Disciplined capital allocation focused on profitability and cash flow
growth
• Conservative financial management
• Deliver competitive total return comprised of both sustainable
growth and income
2
Delivering Organic Production Growth
3
• Oil and liquids production
growing to 50% of total in
2012
• oil and liquids production
growth of 22%
• natural gas production flat
• Production growth
concentrated in:
• Tight Oil ~45% with
netback of ~$50/BOE
• Waterfloods ~ 3% with
netback of ~$48/BOE
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2010 Exit 2011 AA 2011 Exit 2012 AA 2012 Exit
BO
E/d
ay
Oil Gas
175% Organic Reserve Replacement in 2011
4
53% 57%
47% 43%
0
50
100
150
200
250
300
350
20102P Reserves*
20112P Reserves*
MM
BO
E
Crude Oil and Liquids Natural Gas
306 MMBOE 322 MMBOE
• Total 2P reserves increased
by 5%
• Oil reserves increased by
14%
• Oil & liquids are now 57% of
total 2P bookings
• NPV of reserves increased
by 10% in 2011 due to
increased weighting of oil in
portfolio
• NPV of Fort Berthold oil
property up 160% due to
success of drilling program
* Company interest reserves
Competitive Reserve Addition Costs
• 75% of reserve additions
from oil and liquids
• FD&A costs reflect the value
captured in the sale of the
Marcellus interests for $580
million
• F&D costs attractive despite
$150 million of capital that
did not add reserves in 2011
• 273 booked drilling locations
$17.22
$8.57
$26.26
$17.89
$0
$5
$10
$15
$20
$25
$30
2011 F&D* 2011 FD&A*
$/B
OE
Excl. FDC Incl. FDC
* Based on 2P company interest reserves at December 31, 2011. 5
Significant Upside Potential
0
100
200
300
400
500
600
700
800
900
2010Contingent Resources*
2011Contingent Resources*
MM
BO
E
Tight Oil Waterfloods Marcellus
• Contingent resources are
1.5x 2P reserves
• 485 future drilling
locations associated with
contingent resources
• Over 100 oil locations
• Further unassessed
resource potential in
waterfloods, liquids rich
natural gas and North
Dakota tight oil
770 MMBOE
Sold
~270 MMBOE
Converted
~35 MMBOE
Added
+19 MMBOE
485 MMBOE
* Best estimate of contingent resources assessed both internally and externally at Dec 31, 2010 and Dec 31, 2011 6
7
Building a Portfolio of Strategic Land
Cardium/other
new oil plays
30,000 net
acres
Stacked
Mannville
67,000
net acres
Duvernay
70,000
net acres
Montney
33,000 net
acres
Fort Berthold
Bakken/Three
Forks
74,000 net
acres
Marcellus
110,000
net acres
• Over 1 million acres of
undeveloped land within
our portfolio
• Strategic land portfolio
of over 385,000 net
acres
• Added 116,000 net
acres in Canada and
U.S. in 2011
Preserving Flexibility in Weak Gas Price Environment
8
• $1 billion covenant based credit
facility approximately 70% unutilized
after recent equity offering
• Additional funding sources could
include:
• term debt
• sale of equity investment
portfolio
• dividend reinvestment program
• partial reduction of strategic land
through joint venture or sale
• Reduce capex and moderate growth
• Dividend could come under pressure
depending upon oil price and
success in above-mentioned
initiatives
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2011 2012e
Ad
juste
d P
ayo
ut
Rati
o**
Deb
t to
Fu
nd
s F
low
(X
)
Debt to Funds Flow* APO**
* 2011 Funds Flow from Operations reflects trailing 12 months at Dec 31, 2011; Debt as at Dec 31, 2011.
** 2011 Adjusted Payout Ratio (“APO”) in net of A&D activity. 2012E APO includes impact of $345 million equity financing.
1.6 x 1.6 x
154%
185%
Disciplined Capital Allocation
• $800 million capital program, 70% weighting to crude oil
and liquids rich projects
• Organic production growth target of 10% (annual
average)
• 25% of capital directed to Marcellus to delineate
resource, retain leases and add production/reserves;
primarily non-operated
• $100 million allocated to delineate prospective
undeveloped land – Duvernay, Montney, Cardium,
Marcellus
• Expected exit capital efficiencies of $30,000 -
$35,000/BOE/day
9
Expect cash
flow growth
in 2012 as oil
weighting
increases
Fort Berthold Providing Significant Growth
-$200
-$100
$0
$100
$200
$300
$400
$500
(10,000)
(5,000)
-
5,000
10,000
15,000
20,000
25,000
2012 2013 2014 2015$
Millio
ns B
OE
/da
y
Capital Net Op Income Production Free Cash Flow (NOI - Capex)
• Growth potential of 20,000 –
25,000 BOE/day by 2014
• Over 130 future drilling
locations currently identified
• Free cash flow projected in
2013
• Net operating income
exceeds $400 million
by 2015
• Recycle ratios of 2.5 – 5x
• Rail and pipeline
commitments in place for
8,500 bbls/day in 2012 and
14,000 bbls/day in 2013
10
Fort Berthold Leads the Charge in Oil Growth
11
• +160% increase in reserves in 2011 at F&D
cost of $19.16/BOE
• 2012E exit production growth of +70% to
15,600 BOE/day
• 2012 Plans:
• $300 million in capital
• 3 – 4 rigs drilling 90% long HZ wells
• Expected exit capital efficiency of
~$30,000/BOE/day with netback of
~$50/BOE
McKenzie
Dunn
Mountrail
Key Facts
Net Acreage (acres) ~74,000 (90% working interest)
2011 Proved + Probable
Reserves
58.4 MMBOE
(53 future locations)
2011 Best Estimate
Contingent Resources
49 MMBOE
(78 future locations)
12
Fort Berthold Achieving Robust Economics
Long Laterals (9,500 ft. 20 - 24 frac stages), $10 MM/well
Type Curve
30 Day IP 1,160 bbls/day
EUR 800 Mbbls
IRR 60%
Net Present Value (10%)* $13 million
Payout Period 1.6 years
Recycle Ratio 4 – 5x
• EUR estimates increased to 800,000 bbls per long lateral due to
outperformance
• Current well costs are $11 MM, however, targeting $10 MM by mid-year
through change in completions
*Economics are before tax in US dollars based on Feb. 22, 2012 forward prices.
Royalties average 19.5%, plus state production and extraction tax of 8.5%, differential assumption of $16/bbl
NPV includes associated natural gas and liquids of 700 Mcf/bbl with 15% shrinkage and liquids of 140 bbls/MMcf
Crude Oil Waterfloods Support Dividend and Growth
• Represents ~20% of total corporate production
• Significant potential for both drilling and enhanced oil recovery
• Contingent resource estimate represents a 75% increase to 2P waterflood reserves if fully booked
• 2012 Plans:
• $150 capital program advancing enhanced oil recovery and drilling projects focused on Glauconitic, Cardium, Ratcliffe and Lodgepole
13
Glauc “C”
Cardium
Ratcliffe
Lodgepole
Lloydminster
Key Facts
2011 Proved + Probable
Reserves
89.9 MMBOE
2011 Best Estimate
Contingent Resources
56 MMBOE
14
Oil Waterflood Upside Through Improved and
Enhanced Recovery
Asset
OOIP
(MMBBL)
Total
Recovered
(MMBBL,
% OOIP)
2011 YE
2P
Reserves
(MMBOE)
Contingent Resource
(MMBOE)
Total
Recoverable
2011 Net
Operating
Income IOR EOR Total
Medicine Hat, AB 217 17.7 16.7 5.5 21.7 27.2 28% $42.50/BOE
Giltedge, AB 126 17.8 11.0 4.0 11.8 15.8 35% $44.00/BOE
Freda/Skinner
Lake/Neptune, SK
99 14.1 10.2 7.2 0 7.2 32% ~$60.00/BOE
Cadogan, AB 45 4.2 2.4 3.3 0 3.3 22% $54.00/BOE
Virden/Daly, MB 283 78.5 8.2 2.8 0 2.8 32% ~$63.00/BOE
Sub-Total 770 132.3 49.8 22.8 33.5 56.3 31%
• Other waterflood assets with potential IOR/EOR upside:
• Pembina 5-way (Cardium)
• Gleneath (Viking)
• Joarcam (Viking)
• Progress/Pouce Coupe (Boundary B/C)
Note: There are other waterflood properties that contribute to reserves and production within this resource play that are not included above
15
0
5
10
15
20
25
2005AA
2006AA
2007AA
2008AA
2009AA
2010AA
2011AA
2012eAA
2012eExit
MB
OE/
day
Stable Crude Oil Production Base from Waterfloods
• Low base decline of ~12%
• ~50% of net operating
income reinvested to
maintain production
• 2012E annual production:
17,200 BOE/day, +3%
from 2011
Sold ~2,800 non-core
BOE/day
16 16
Marcellus: Retaining Leases for Future Value Capture
• 65,000 net operated acres with
90% working interest
• ~$40 million in capital in 2012
focused on delineation
• 45,000 net non-operated acres with
20% avg. working interest
• Major non-op partners:
• EXCO (22% WI)
• Chief (18% WI)
• ~$150 million in capital in 2012
focused on lease retention and
reserve/production additions
• 110,000 net acres with ~450
future drilling locations to
support future reserve and
production growth
• Contingent resource
estimate of 2.3 Tcf – nearly
triple our 2P natural gas
reserves
• 2012E exit production: > 70
MMcf/day (+180%)
• 2012 Plans:
• $190 million in capital to
drill and bring on-stream
~20 net wells
0%
20%
40%
60%
$2.50 $3.50 $4.50
BTA
X IR
R
NYMEX Gas ($US/MMBtu)
9.0 Bcf Type Curve
4.5 Bcf Type Curve
17
Marcellus Well Economics
Assumes well cost of $7.0 MM
7.0 Bcf Well 9.0 Bcf Well
NYMEX
$/MMbtu IRR
Payout*
(Years)
NPV 10%
($MM) IRR
Payout*
(Years)
NPV 10%
($MM)
$4.50 19.7% 4.0 $2.2 36.6% 2.6 $5.3
$3.50 8.0% NA ($0.5) 18.3% 4.2 $1.8
$2.50 0% NA ($3.1) 3% NA ($1.7)
* Undiscounted payout shown
Virtually all of non-op
spend in 2012 is in areas
with 7 – 9 Bcf type wells
Growing Inventory of Liquids Rich Natural Gas Potential
18
• Spending $80 million in 2012 to assess and
delineate future development of these plays
• Montney:
• Target EUR of ~5.0 Bcf/well with 20-30
bbls/MMcf liquids
• 2012: 1 HZ appraisal well plus testing 2011
vertical
• Stacked Mannville:
• Target EUR of ~5.0 Bcf/well with 5-15
bbls/MMcf liquids
• 2012: 2 operated HZ Wilrich wells plus
pipeline from Minehead to South Ansell
• Duvernay:
• Target EUR of 3.5 Bcf/well with 75-100
bbls/MMcf liquids
• 2012: 2 appraisal wells
Montney
Duvernay
Stacked Mannville
19
Well Positioned to Deliver on our Strategy
• Delivering production and reserve growth
• Increasing oil and liquids weighting
• Financial flexibility
• Portfolio of emerging plays with future
opportunity
• Proven A&D capability
Diverse asset
base rich in
development
opportunities that
support
sustainable
growth and
income
The Game Plan Supplemental Information
2012 Budget Delivers Above-Average Growth
21
2011 Actual 2012E Guidance Year over Year Change
Average annual production
Production mix
Tight Oil
Waterfloods*
Marcellus
75,332 BOE/day
44% oil & liquids
13,616 BOE/day
16,623 BOE/day
20,524 Mcf/day
83,000 BOE/day
50% oil & liquids
19,500 BOE/day
17,200 BOE/day
55,000 Mcf/day
+10%
+43%
+3%
+168%
Exit production
Production mix
Tight Oil
Waterfloods*
Marcellus
82,000 BOE/day
47% liquids
16,703 BOE/day
18,414 BOE/day
25,213 Mcf/day
88,000 BOE/day
50% liquids
22,500 BOE/day
18,500 BOE/day
>70,000 Mcf/day
+7%
+35%
+1%
>175%
Development capital spending
% Oil and Liquids
Tight Oil
Waterfloods
Marcellus
$866 million
64%
$375 million
$164 million
$210 million
$800 million
66%
$350 million
$150 million
$190 million
-8%
-7%
-9%
-10%
Operating Costs $10.23/BOE $10.40/BOE +2%
General and Administrative $3.44/BOE $3.55/BOE +3%
Royalties 18% 21% +3%
* 2011 waterflood production adjusted to reflect internal reclassification of properties
22
34%
66%
Institutional Retail
Enerplus Share Ownership
35%
63%
2%
Canada US Other
As of December 31, 2011 As of January 23, 2012
Investor Composition Geographic Composition
23
Hedging
The following is a summary of the financial contracts in place at February 10, 2012
expressed as a percentage of our forecasted net production volumes (shading denotes
downside protection):
* There are no natural gas hedges in place at this point in time
Crude Oil (US$/bbl)
January 1, 2012 – December 31,
2012
January 1, 2013 –
December 31, 2013
WTI Purchased Puts (floor prices) $103.00 -
% 3% -
WTI Sold Puts (limiting downside protection) $65.00 $63.00
% 7% 3%
WTI Swaps (fixed price) $95.83 $101.20
% 59% 10%
WTI Sold Calls (capped price) $133.00 -
% 3% -
WTI Purchased Calls (repurchasing upside) $103.00 $102.95
% 3% 3%
Brent – WTI Spread $13.82 -
% 12% -
24
North Dakota Takeaway Capacity
25
Duvernay Shale – Willesden Green
• Early stage liquids rich natural
gas play in central Alberta
• Targeted type well:
• Hz well cost of ~$12 million
• 30 day IP of ~5 MMcf/day
• EUR of ~3.5 Bcf with 75 - 100
bbls/MMcf
• Focus on early stage
evaluation in 2012
• 2 wells planned for Q3 - Q4
Enerplus Land Land sales since Dec. 2010
Licensed Duvernay Wells
R/R Wells
Pre-existing Well Control
Key Facts
Region Willesden Green, AB
Net Acreage ~70,000 acres (+100 sections)
Est. OGIP ~65 Bcf/section
Est. Density 4 wells/section
Est. Recovery 20%
26
Montney – Cameron/Julienne Creek
• Targeted type well:
• Hz well cost of $6 - 7 million
• EUR ~5.5 Bcf/well with 20 - 30
bbls/MMcf
• Focus on early stage evaluation
with 1 HZ appraisal well planned
for 2012, completion of 2011
vertical test
• Slower pace than initially planned
in response to current price
pressures
Key Facts
Region Cameron/Julienne Creek, BC
Net Acreage (acres) 33,000 acres (+50 sections)
Estimated OGIP 150 Bcf/section
Estimated Density 8-12 wells/section
Estimated Recovery 18-25%
27
Stacked Mannville – Alberta Deep Basin
• Targeted Wilrich type well:
• Hz well cost of $6 - 7 million
• EUR of ~5.0 Bcf/well with 5 - 15
bbls/MMcf
• 2 HZ Wilrich wells planned in early
2012 plus building pipeline from
Minehead to South Ansell to tie-in the
field
Key Facts
Region Pine Creek/Ansell/Hanlan, AB
Net Acreage (acres) 67,000 acres (+10 sections)
Estimated OGIP 15 - 25 Bcf/section
Estimated Density 2 - 3 wells/section
Estimated Recovery 40 - 80%
Disclaimers
28
Assumptions
All economics contained have been calculated using forward prices and costs as of February 22, 2012. All amounts are stated in Canadian dollars unless otherwise specified.
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
This presentation contains references to "BOE" (barrels of oil equivalent), "Mcfe" (thousand cubic feet of gas equivalent), "Bcfe" (billion cubic feet of gas equivalent) and "Tcfe"
(trillion cubic feet of gas equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs,
and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Mcfes, Bcfes and Tcfes. BOEs, Mcfes, Bcfes and Tcfes may be misleading,
particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not
represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy
equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent",
respectively.
Presentation of Production and Reserves Information
In accordance with Canadian practice, production volumes and revenues are reported on a “Company interest” basis, before deduction of Crown and other royalties, plus
Enerplus’ royalty interest. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company interest reserves"
using forecast prices and costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators
("NI 51-101"), being Enerplus' working interest before deduction of any royalties), plus Enerplus' royalty interests in reserves. “Company interest reserves" are not a measure
defined in NI 51-101 and do not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or
disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2011, which 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, 2011 ("our AIF") which will be
available in mid-March 2012 on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, the Annual Information Form will form part of
our Form 40-F that will be 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 concurrently with this presentation for more complete disclosure on our operations.
Contingent Resource Estimates
This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources"
are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable
due to one or more contingencies. Contingencies may include factors such as ultimate recovery rates, economic, legal, environmental, political and regulatory matters or a lack of
markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associated with a project in the early evaluation stage.
Enerplus expects to develop these contingent resources in the coming years however it is too early in their development for these resources to be classified as reserves at this
time.
There is no certainty that we will produce any portion of the volumes currently classified as “contingent resources”. The “contingent resource” estimates contained herein are
presented as the "best estimate" of the quantity that will actually be recovered, effective as of December 31, 2011. A "best estimate" of contingent resources means that it is
equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabil istic methods are used, there should be at least a 50%
probability that the quantities actually recovered will equal or exceed the best estimate.
Disclaimers
29
For additional information regarding the primary contingencies which currently prevent the classification of our disclosed “contingent resources” associated with our Marcellus
shale gas assets, our North Dakota Bakken properties and our crude oil waterflood properties as reserves and the positive and negative factors relevant to the “contingent
resource” estimates, see our Annual Information Form for the year ended December 31, 2010 (and corresponding Form 40-F) dated March 11, 2011, a copy of which is available
under our SEDAR profile at www.sedar.com and a copy of the Form 40-F which is available under our EDGAR profile at www.sec.gov.
F&D and FD&A Costs
F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in
the year plus the change in estimated future development costs in the year, by the additions to proved reserves in the year, and (ii) in the case of F&D costs for proved plus
probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the
additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during
that year in estimated future development costs generally will not reflect total finding and development costs related to its reserves additions for that year.
FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the
cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves including net acquisitions in
the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred
in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves including net acquisitions in the year. The
aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally
will not reflect total finding, development and acquisition costs related to its reserves additions for that year.
Non-GAAP Measures
In this presentation, we use the terms “funds flow”, "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "F&D costs"
and “FD&A costs” as measures of operating performance. We calculate funds flow based on cash flow from operating activities before changes in non-cash operating working
capital and decommissioning expenditures, all of which are measures prescribed by Canadian generally accepted accounting principles (“GAAP”) which were revised effective
January 1, 2011 to converge with International Financial Reporting Standards (“IFRS”) and which appear in our Consolidated Statements of Cash Flows. We calculate "payout
ratio" by dividing dividends to shareholders by funds flow. "Adjusted payout ratio" is calculated as cash dividends to shareholders plus development capital and office
expenditures, divided by funds flow from operating activities.
Enerplus believes that, in addition to net earnings and other measures prescribed by GAAP, the terms “funds flow”, "payout ratio", "adjusted payout ratio", "F&D costs" and
“FD&A costs” are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are
not measures recognized by GAAP and do not have a standardized meaning prescribed by GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable
to similar measures presented by other issuers.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are not
comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined
differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules.
Disclaimers
30
In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes,
which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of
applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC
mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period. Additionally, the SEC prohibits disclosure of oil and gas
resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not construed as reserves. For a description of the definition
of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see “Information Regarding Reserves, Resources and Operational Information” above.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This presentation contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any
of the words "expect", "anticipate", "continue", "estimate", “guidance”, "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", “budget”, "strategy" and
similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, these presentations contains forward-looking information
pertaining to the following: Enerplus' strategy to deliver both income and growth to investors and Enerplus' related asset portfolio; future returns to shareholders from both
dividends and from growth in per share production and reserves; future capital and development expenditures and the allocation thereof among our resource plays and assets;
future development and drilling locations and plans; the performance of and future results from Enerplus' assets and operations, including anticipated production levels and
decline rates; future growth prospects, acquisitions and dispositions; the volumes and estimated value of Enerplus' oil and gas reserves and contingent resource volumes and
future commodity price and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; the volume and product mix of Enerplus' oil and gas production;
securing necessary infrastructure and third party services; the amount of future asset retirement obligations; future cash flows and debt-to-cash flow levels; potential asset sales;
returns on Enerplus' capital program; Enerplus' tax position; and future costs, expenses and royalty rates.
The forward-looking information contained in this presentation reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that
Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; the general continuance
of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserve
and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and cash flow to fund Enerplus' capital and
operating requirements as needed; and the extent of its liabilities. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking
information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information and involves
known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information
including, without limitation: changes in commodity prices; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from development
plans or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans by Enerplus or by third party
operators of Enerplus' properties; increased debt levels or debt service requirements; inaccurate estimation of Enerplus' oil and gas reserves and resources volumes; limited,
unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; and certain
other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in Enerplus' Annual Information Form and Form
40-F described above).
The forward-looking information contained in this presentation speak only as of the date of this presentation, and none of Enerplus or its subsidiaries assumes any obligation to
publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Jo-Anne M. Caza
Vice President, Corporate & Investor Relations
403-298-2273
Garth Doll
Manager, Investor Relations
403-298-1218
1-800-319-6462
www.enerplus.com
The Dome Tower
Suite 3000, 333 7th Ave SW
Calgary, AB Canada
T2P 2Z1
Investor Relations Contacts
