the game plan may 2012 - enerplus
TRANSCRIPT
The Game Plan
Investor Update
May 2012
• Own a portfolio of oil and gas resource plays in North America which
includes:
• early stage assets that offer scope and scale as well as future option value
• producing assets with development opportunity
• Improve the profitability of our assets and continue to demonstrate our
execution capability
• Delineate prospective resource and strategically monetize a portion to
facilitate our growth and income model
• Pursue strategic acquisitions complementary to the existing portfolio
• Maintain a healthy balance sheet
• Committed to yield
Corporate Strategy
1
Dividends/Distributions - a Key Component of Shareholder Return
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$0.00
$1.75
$2.72
$3.32
$5.65
$3.29
$2.83
$3.68
$2.60 $2.58
$3.97
$4.52
$3.12 $3.32
$5.26
$5.61
$3.25
$4.29 $4.20
$4.47
$5.04 $5.04 $4.89
$2.16 $2.16 $2.16
$-
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1
CD
N $
’000s
Cumulative dividends paid Cash dividends / distributions per share
$91.89/share paid since
inception*
* As of December 31, 2011
Paid over $6 billion in
cumulative dividends*
Delivering Organic Production Growth
3
• Oil and liquids production
growing to 50% of total in 2012
• oil production growth of 22%
• natural gas production flat
• Production growth
concentrated in:
• Tight Oil ~45% growth with
netback of ~$50/BOE
• Waterfloods ~ 3% growth 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
• 2P reserves increased by 5%
• Replaced 300% of our oil
production, growing 2P oil
reserves by 14%
• NPV of reserves increased by
10% in 2011 due to increased
weighting of oil in portfolio
• NPV of Fort Berthold oil
property up 160% due to
success of drilling program
* Company interest reserves
Competitive Finding & Development Costs
(1) Proved + probable reserves at December 31, 2011 including future development capital
5
$26.26 $26.59
$22.68
$0
$5
$10
$15
$20
$25
$30
Enerplus Oil weightedpeers
All peers
$/B
OE
F&D Cost/BOE(1)
$17.89
$23.84
$20.32
$0
$5
$10
$15
$20
$25
Enerplus Oil weightedpeers
All peers
$/B
OE
FD&A Cost/BOE(1)
Oil weighted peers includes: Baytex, Crescent Point, PennWest, Petro Bakken
All peers includes above as well as: ARC, Bonavista, NAL, Pengrowth, Progress, Vermillion
75% Oil* 83% Oil*
61% Oil*
* % of 2P reserve additions attributable to crude oil
Significant Upside Potential
• 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
* Best estimate of contingent resources assessed both internally and externally at Dec 31, 2010 and Dec 31, 2011 6
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2010Contingent Resources*
2011Contingent Resources*
Tcfe
Natural Gas
Marcellus
0
25
50
75
100
125
150
2010Contingent Resources*
2011Contingent Resources*
MM
BO
E
Crude Oil
Waterfloods Tight Oil
Sold
~1.6 Tcfe
Converted
~5
MMBOE
Added +19
MMBOE
Converted
~30
MMBOE
7
Opportunity Rich Portfolio
Cardium/other
new oil plays
30,000 net
acres
Stacked
Mannville
67,000
net acres
Duvernay
72,000
net acres
Montney
33,000 net
acres
Fort Berthold
Bakken/Three
Forks
74,000 net
acres
Marcellus
110,000
net acres
• Over 200 drilling locations
identified on our oil assets
• Significant additional
upside through increased
density, EOR and drilling
on undeveloped lands
• Over 575 drilling locations
identified on our natural gas
assets
• Over $10 billion of
potential investment on
undeveloped acreage
Waterfloods
14 properties
with IOR &
EOR
Preserving Financial Flexibility
8
• We currently have a strong balance sheet but low gas prices are creating funding
challenges (1.6x debt to funds flow at March 31, 2012)
• Actions taken to date include:
• February 8, 2012 equity issue - $330 million
• Stock Dividend Program - $70 million estimated proceeds in 2012
• extending credit capacity with term debt - $405 million
• We have plans to manage debt levels through a number of initiatives over the
next 18 months
• monetizing our equity portfolio
• joint venture or sale of a portion of undeveloped land
• $250 to $500 million in total
• Depending on the progress with respect to these funding initiatives and realized
commodity prices, there could be downward pressure on:
• capital spending and growth rates
• dividends
9
Implementing Stock Dividend Program (“SDP”)
• Benefits:
• All shareholders are now eligible to participate
• Shareholders can elect to receive cash dividends or Enerplus shares
• 5% discount to current market price and no fees or commissions
• Participation in the SDP is not expected to generate dividend income
for Canadian shareholders
• SDP participation is completely optional
• Replaces current DRIP
2012 Capital Program Delivers 10% Production Growth
• Total 2012 capital budget of $800 million delivers 10% growth in annual
average production
• 70% of capital directed toward oil and natural gas liquids projects
• No spending on Canadian shallow gas assets
• Marcellus focused on lease retention and limited delineation on operated leases
• $80 million directed toward delineation of new plays - Montney, Duvernay,
emerging oil plays and operated Marcellus acreage
8
2012 Capital Spending Breakdown 2012E
($ millions)
Tight Oil - $300 million at Fort Berthold $350
Waterfloods $150
Marcellus - $150 million non-operated/$40 million operated $190
Deep Basin – primarily Stacked Mannville $65
Our Operational Focus in 2012
• Execution at Fort Berthold
• Reduce cycle times on new wells
• Reduce downtime
• Test downspacing
• Continue to advance on our waterflood projects
• Advance EOR pilots at Giltedge & Med Hat
• Drilling/injector conversions to enhance efficiencies
• Delineate new resource plays in Canada
• Montney, Duvernay, emerging oil plays
• Spend to maintain Marcellus land position
• Continued focus on cost management
• Capital efficiencies
• Operating costs
11
Expected exit
capital efficiencies
of $30,000 -
$35,000/BOE/day
• Production averaged 79,200 BOE/day (+3% from Q4 2011)
– 47% oil and liquids, up from 44% in 2011
• Invested $317 million in development capital drilling 25 net wells with
14 net wells brought on-stream
– $138 million focused at Ft. Berthold
• Generated funds flow of $163 million ($0.86/share)
– unchanged vs Q4 2011 due to higher oil production offsetting weak
natural gas prices
• Debt to 12 trailing month funds flow ratio of 1.6x
• Operating costs and G&A in line with expectations at $10.00/BOE
and $3.51/BOE respectively
First Quarter Results Meeting Expectations
12
Fort Berthold Leads the Charge in Oil Growth
13
Key Facts
Net Acreage (acres) ~74,000 (115 sections)
2011 P+P Reserves 55.4 MMBOE
2011 Best Estimate
Contingent Resources
49 MMBOE
2011 Q4 Production
2012 Q1 Production
6,800 BOE/day
8,700 BOE/day
Current Operated and Non-Operated Locations
• Concentrated, top tier land position in North
Dakota
• Average 90% working interest
• 130+ future drilling locations; 32 horizontal
operated wells drilled to date
• Expected netback of $50 - $55/BOE in 2012
14
Fort Berthold Bakken Economics
Bakken Long Laterals
9,500 ft. 20 - 24 frac stages, $11 MM/well
Type Curve
30 Day IP 1,240 bbls/day
EUR:
Oil
Gas
NGLs
940 MBOE
800 Mbbls
470 MMcf
75 Mbbls
IRR 90%
Net Present Value (10%)* $17 million
Payout Period 1.2 years
Recycle Ratio 4.0x
* Economics are before tax in US dollars based on March 26, 2012 forward prices. Royalties average 19.5%, plus state production and
extraction tax of 8.5%
Fort Berthold Cost Mitigation & Field Optimization
15
• Improved drilling cycle times
• Best rig now averaging 30 days for long drill well versus 37 day average
• Completion design
• Testing different completion techniques
• Optimize stages, water, proppant
• Water management
• Full year of salt water disposal wells
• Reduction in completion costs
• Added second SWD well
• Evaluating piping system for SWD
• Continue infrastructure build out for well tie-ins
• 50% of wells tied-in now, 75% expected by year-end
• Production optimization
• Increase in service rigs to improve uptime – target 50% reduction in downtime
Canadian Waterflood Assets
Key Facts
OOIP ~1.6 billion barrels (net)
P+P Reserves (YE 2011) 90 million barrels net
(26% recovery)
Recovery to date 21%
Best Est. Contingent
Resources
56.3 million barrels
Average Oil Quality 30° API
2012E Annual Production 17,000 BOE/day
21% of total
16
IOR – Improved Oil Recovery (Secondary recovery)
EOR – Enhanced Oil Recovery (Tertiary recovery)
• Line of sight to grow production by ~5% per year through focused IOR/EOR
• 50% of net operating income reinvested to maintain production
• 2012 program in support of strategy
• Spend $150 million on ~40 horizontal high working interest operated oil wells and upgrading facilities
• Implement EOR projects
17
Defining the IOR/EOR Opportunity in Canada
Asset
OOIP
(net)
(MMBbl)
2011
YE 2P
Reserves
(MMBOE)
Total
Recovered
(MMBbl)
Contingent
Resource
(MMBbl)
Incremental
Recoverable
2011 Net
Operating
Income IOR EOR Total
Medicine Hat, AB 217 16.7 8% 5.5 21.7 27.2 13% $42.50/BOE
Giltedge, AB 126 11.0 14% 4.0 11.8 15.8 13% $44.00/BOE
Freda/Skinner
Lake/Neptune, SK
99 12.7 14% 7.2 0 7.2 7% ~$60.00/BOE
Cadogan, AB 45 2.4 9% 3.3 0 3.3 7% $54.00/BOE
Virden/Daly, MB 283 8.2 28% 2.8 0 2.8 1% ~$63.00/BOE
Sub-Total* 770 51.0 17% 22.8 33.5 56.3 7%
* There are other waterflood properties that contribute to reserves and production within this resource play that are not included above
• EOR potential also at
Freda/Skinner Lake/Neptune;
Virden/Daly
• ~340 net locations to unlock
potential value of our assets
• Incremental 5 -15% recovery
Further Upside Potential
Field
OOIP
(MMBbl)
2011
YE 2P
Reserves
(MMBOE)
Recovery
Factor for
Oil
Reserves
Total
Recovered
EOR/
IOR
Pembina 252 21.6 35% 28% Both
Gleneath 103 4.4 23% 19% Both
Joarcam 166 3.2 42% 40% Both
Brooks 193 12.5 34% 30% IOR
18 18
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 growth
• 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
Well Performance Continues to Exceed Expectations
19
0
500
1000
1500
2000
2500
3000
0 30 60 90 120 150 180 210 240 270 300 330 360
Cu
mu
lati
ve
Pro
du
cti
on
(M
Mc
fe)
Days Producing
Top 5 Wells
Average Actual Production
6.0 Bcfe Type Curve
3.5 Bcfe Type Curve
• Average EURs have
increased from 3.2 – 3.4
Bcf/well to 6.6 Bcf/ well
• Increased land utilization
from 55% to 65%
• High EUR estimate has
increased from 5 Bcf/well
in 2009 to an average of
11 Bcf/well today in
Susquehanna County
N.E. PA Well Performance
20
2012 Non-Operated Plans Focused on Lease Retention
• $150 million capital budget for 2012
• Rig count has dropped while maintaining the
minimum needed for lease obligations
• 19 net new drills planned in 2012, 18 on-streams
• ~50% of 2012 drilling planned in areas with water
and pipeline infrastructure already in place
• 90% of 2012 capital program targeted in locations
with anticipated EURs of 7-9 Bcf/well
• ~50% in 9 Bcf/well areas
EXCO Resources
Chief O&G & CHK
16
13 10
0
5
10
15
20
Sep-11 Jan-12 Current
Planned 2012 Rig Activity by Non-Op Partners on Enerplus Acreage
Partners are managing activity in current market conditions
21
• Approximately 170,000 net acres of
high working interest land
throughout the region
• Includes 100% working interest in
approximately 145,000 undeveloped
acres
• Multiple contiguous acreage blocks
• Potential of liquids rich zones
• 2012 capital focused on delineating
the resource given price
environment
• Duvernay – 2 vertical strat wells
• Montney - 1 vertical strat and 1 hz
• SM Wilrich – 2 hz producers
Montney Potential
• 33,000 net acres of
undeveloped land
Stacked Mannville
Potential
• 67,000 net acres of land
(42,000 undeveloped)
21
Large, long tenure, high working
interest land holdings
Defining the Gas Opportunity (Deep Gas)
Duvernay Potential
• 72,000 net acres of
undeveloped land
Outlook
• Good mix of early stage, high growth, and mature oil and gas properties
• Abundance of growth opportunities in our portfolio today – not reliant on
acquisitions
• We had a strong year in 2011 with respect to organic reserve replacement
through organic growth and F&D costs
• Oil weighting is increasing:
• 75% of 2011 reserve additions were from oil and liquids increasing overall to 57% of proved
plus probable
• Production share of oil and liquids ~50% by end of 2012
• 70% of capital spending directed towards oil & liquids
• We have a healthy balance sheet and plans to manage our debt levels in the context
of weak natural gas prices
• Objective is to deliver competitive total return comprised of sustainable growth and
income
22
The Game Plan Supplemental Information
24
17%
18%
48%
17%
US/Intl Institutional Canadan Institutional
US/Intl Retail Canada Retail
Enerplus Share Ownership
35%
63%
2%
Canada US Other
As of December 31, 2011 As of January 23, 2012
Investor Composition Geographic Composition
Total Retail
65%
Total Institutional
35%
25
Hedging
• 62% of net oil production hedged
at US$96.22/bbl
• Physical fixed price contracts in
place for 27% of net natural gas
production at CAD$2.17/Mcf –
April – October, 2012
42%
58%
Hedged Spot
62%
38%
Hedged Spot
2012 Crude Oil 2013 Crude Oil
• 42% of net oil production hedged
at US$103.00/bbl
• No natural gas hedges in place at
this time
* As of May 2012
26
Bakken Well Results Continue to Outperform
-
200
400
600
800
1,000
1,200
1,400
0
50
100
150
200
250
300
1 3 5 7 9 11 13 15 17 19 21D
aily P
rod
ucti
on
(b
bl/d
ay)
Cu
mu
lati
ve P
rod
ucti
on
(b
bls
)
Months
Bakken Long Well Performance
Cumulative Type Curve Actual Cumulative Average
Daily Production Type Curve Actual Daily Average
7 wells
5 wells
4 wells
3 wells
2 wells
1 well
0
100
200
300
400
500
600
700
-
20
40
60
80
100
120
140
160
180
1 3 5 7 9 11 13 15 17 19 21 23
Daily P
rod
ucti
on
(b
bl/d
ay)
Cu
mu
lati
ve P
rod
ucti
on
(b
bls
) Months
Bakken Short Well Performance
Cumulative Type Curve Actual Cumulative Average
Daily Production Type Curve Actual Daily Average
PLACEHOLDER ONLY:
NEED THE daily type curve
18 wells
11 wells
9 wells
5 wells
3 wells
2 wells
1 well
27
North Dakota Takeaway Capacity
• Rail and pipeline commitments in place for 8,500 bbls/day in 2012 and 14,000 bbls/day in 2013
• 2,000 to 3,000 bbls/day directly exposed to LLS pricing through Feb 2014
Non-Operated (~47,000 net acres in PA)
• Operated primarily by Chief, Exco and Chesapeake
• Anticipate 30% - 35% of leasehold to be held by production by end of 2012
• Approximately 22,000 net acres expire in 2013
• Expect majority to be either extended under pre-negotiated options or to be held by production via 2012-
2013 drilling activity results in ~70% of prospective acreage held by end of 2013
Operated (~68,000 net acres)
• Pennsylvania (~7,000 net acres)
• Majority of leases expire in 2015
• West Virginia/Maryland (~61,000 net acres)
• Expirations (acres):
• 2012: 28,000 acres - 95% of leasehold can be extended for $1.6MM
• 2013: 29,000 acres - 90% of leasehold can be extended for $15.8MM
• 2014+: 4,000 acres
Marcellus Lease Tenure
28
29
Stacked Mannville
• Acquiring and utilizing 3D seismic
• Drilled 5 Hz delineation wells to date, 3
others licensed and ready to execute
• Liquids ratios of 7 – 30 bbls/MMcf
• Additional de-risking ongoing by competitors
and partners
Key Facts
Key properties Pine Creek to Hanlan
Net Acreage (acres) ~67,000 total (42,000 undeveloped)
Future HZ Drilling
Locations
100 - 200
Expected EUR/Well 4.0 - 6.0 Bcfe
Enerplus working interest lands
Contiguous land blocks in highly
prospective regions
30
Wilrich Type Curve Economics
4.0 Bcf Well 6.0 Bcf Well
AECO
($/Mcf)
IRR
%
Payout
(Years)
NPV
10%
($MM)
IRR
%
Payout
(Years)
NPV
10%
($MM)
$4.00 30 2.7 3.6 67 1.6 8.6
$3.00 16 4.0 1.1 40 2.2 5.1
$2.00 2 9.5 -1.4 18 3.7 1.4
Capital* $7.1 million $7.1 million
30 Day
IP 3,800 Mcf/day 6,000 Mcf/day
Liquids 7 bbls/MMcf 7 bbls/MMcf
BESC $2.81/Mcf $1.61/Mcf
• Type curves are based on offset data
and are supported by our well results
• Positive drilling results to date:
• Horizontal drill - 13 MMcf/day (facility
constrained) peak rate production at
14 Mpa after 165 hours with 15,549
bbls of water recovered
• Produced at 10 MMcf/day for
first 30 days
• Second horizontal drill - 31 MMcf/day
(facility constrained) peak rate
production at 19 Mpa after 90 hours
with 6,900 bbls of water recovered
* Capital assumes pad drilling
31
Progress/Petronas
North Montney JV
(Lily)
Enerplus Julienne Creek Lands
North Montney Regional Pool
Progress Town
3D seismic outline
Painted Pony Blair
Montney Vert. Test Well
T North Sales Line
Montney – Cameron/Julienne Creek
• 3D seismic purchased and
reprocessed
• Existing well and vertical test well
indicate approximately 300 metres
of Montney thickness
• Rock analysis indicates good
reservoir development
• Enerplus vertical testing upper and
lower Montney:
• Drilled to 2,400 metres,
positive gas tests that
support type curve
Key Facts
Key Properties Cameron/Julienne Creek
Net Acreage ~33,000 acres (+50 sections)
Estimated OGIP 150 Bcf/section
Future Hz Drilling
Locations
350 - 400
Expected
EUR/Well
4.0 – 6.0 Bcfe
32
Upper Montney Type Curve Economics
4.0 Bcf Well 5.0 Bcf Well 6.0 Bcf Well
AECO
($/Mcf)
IRR
%
Payout
(Years)
NPV
10%
($MM)
IRR
%
Payout
(Years)
NPV
10%
($MM)
IRR
%
Payout
(Years)
NPV
10%
($MM)
$4.00 25 3.5 2.5 40 2.6 4.3 57 2.0 6.2
$3.00 15 5.3 0.8 25 3.7 2.4 35 2.8 4.0
$2.00 4 10.8 (1.2) 10 6.7 0.1 17 4.8 1.4
Capital $6.2 million $6.2 million $6.2 million
30 Day IP 4,000 Mcf/day 5,000 Mcf/day 6,000 Mcf/day
Liquids 10-15 bbls/MMcf 10-15 bbls/MMcf 10-15 bbls/MMcf
BESC $2.78/Mcf $1.99/Mcf $1.47/Mcf
• Type curves are based on wells in the North Montney trend (Town & Blair) and are supported by
our vertical Montney test well
• Capital assumes pad drilling
33
• Duvernay has analogous rock characteristics to the Eagleford
• Prolific over-pressured Devonian source rock
• Within the gas condensate window, based on:
• Offsetting well control and reported competitor activity
• Equivalent thermal maturity and depth to proven liquid-rich
Kaybob area
• Existing and newly announced mid-stream gas infrastructure,
including deep cut gas plants, provides numerous options for
product marketing
• 4 well/section development provides us with over 400
future Hz drilling locations
• Favorable royalty of 5% for first 5 years of production
Why the Duvernay Shale at Willesden Green?
110 sections in the
gas condensate
window with
net OGIP of
+7 Tcf
34
Duvernay Shale – Willesden Green
• Early stage liquids rich natural
gas play in central Alberta
• Over-pressured at ~56MPa
• Targeted type well:
• Hz well cost of ~$12 million
• 30 day IP of ~5 MMcf/day
• Liquids 75 - 100 bbls/MMcf
• Focus on early stage
evaluation in 2012
• 2 wells planned for Q3/Q4
Key Facts
Key Properties Willesden Green, AB
Net Acreage ~70,000 acres (110 sections)
Est. OGIP ~65 Bcf/section
Est. Density 4 wells/section
Expected
EUR/Well
3.5 Bcf
Bellatrix
Sinopec Daylight
Sirius
Antelope COP
COP ECA
Bonavista
ECA
ECA ECA
TLM
Enerplus Duvernay
Land sales (since Dec/2010)
Licenced Wells
Drilled/Drilling Wells
Duvernay Penetrations
Disclaimers
35
Assumptions
All economics contained have been calculated using forward prices and costs as of March 26, 2012. All amounts are stated in Canadian dollars unless otherwise specified.
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
This presentation contains references to "BOE" (barrels of oil equivalent), "Mcfe" (thousand cubic feet of gas equivalent), "Bcfe" (billion cubic feet of gas equivalent) and "Tcfe"
(trillion cubic feet of gas equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs,
and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Mcfes, Bcfes and Tcfes. BOEs, Mcfes, Bcfes and Tcfes may be misleading,
particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not
represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy
equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent",
respectively.
Presentation of Production and Reserves Information
In accordance with Canadian practice, production volumes and revenues are reported on a “Company interest” basis, before deduction of Crown and other royalties, plus
Enerplus’ royalty interest. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company interest reserves"
using forecast prices and costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators
("NI 51-101"), being Enerplus' working interest before deduction of any royalties), plus Enerplus' royalty interests in reserves. “Company interest reserves" are not a measure
defined in NI 51-101 and do not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or
disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2011, which include complete disclosure of our oil and gas reserves and other
oil and gas information in accordance with NI 51-101, are contained within our Annual Information Form for the year ended December 31, 2011 ("our AIF") which is available on
our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally, the Annual Information Form is part of our Form 40-F that is filed with the U.S.
Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial
statements filed on SEDAR and EDGAR concurrently with this presentation for more complete disclosure on our operations.
Contingent Resource Estimates
This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources"
are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable
due to one or more contingencies. Contingencies may include factors such as ultimate recovery rates, economic, legal, environmental, political and regulatory matters or a lack of
markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associa ted 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
36
For additional information regarding the primary contingencies which currently prevent the classification of our disclosed “contingent resources” associated with our Marcellus
shale gas assets, our North Dakota Bakken properties and our crude oil waterflood properties as reserves and the positive and negative factors relevant to the “contingent
resource” estimates, see our Annual Information Form for the year ended December 31, 2011 (and corresponding Form 40-F) dated March 9, 2012, a copy of which is available
under our SEDAR profile at www.sedar.com and a copy of the Form 40-F which is available under our EDGAR profile at www.sec.gov.
F&D and FD&A Costs
F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in
the year plus the change in estimated future development costs in the year, by the additions to proved reserves in the year, and (ii) in the case of F&D costs for proved plus
probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated future development costs in the year, by the
additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during
that year in estimated future development costs generally will not reflect total finding and development costs related to its reserves additions for that year.
FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the
cost of net acquisitions incurred in the year plus the change in estimated future development costs in the year, by the additions to proved reserves including net acquisitions in
the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred
in the year plus the change in estimated future development costs in the year, by the additions to proved plus probable reserves including net acquisitions in the year. The
aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally
will not reflect total finding, development and acquisition costs related to its reserves additions for that year.
Non-GAAP Measures
In this presentation, we use the terms “funds flow”, "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "F&D costs"
and “FD&A costs” as measures of operating performance. We calculate funds flow based on cash flow from operating activities before changes in non-cash operating working
capital and decommissioning expenditures, all of which are measures prescribed by Canadian generally accepted accounting principles (“GAAP”) which were revised effective
January 1, 2011 to converge with International Financial Reporting Standards (“IFRS”) and which appear in our Consolidated Statements of Cash Flows. We calculate "payout
ratio" by dividing dividends to shareholders by funds flow. "Adjusted payout ratio" is calculated as cash dividends to shareholders plus development capital and office
expenditures, divided by funds flow from operating activities.
Enerplus believes that, in addition to net earnings and other measures prescribed by GAAP, the terms “funds flow”, "payout ratio", "adjusted payout ratio", "F&D costs" and
“FD&A costs” are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are
not measures recognized by GAAP and do not have a standardized meaning prescribed by GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable
to similar measures presented by other issuers.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are not
comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined
differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules.
Disclaimers
37
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