1. business and industrial
2. energy
3. natural gas

ERF: TSX & NYSE
Bank of America Merrill Lynch 2014 Energy Conference
November 13, 2014
Forward Looking Information Advisory
FORWARD-LOOKING INFORMATION AND STATEMENTS
This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking
information"). The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "objective", "ongoing", "may", "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, this
presentation contains forward-looking information pertaining to the following: expected 2014 and 2015 average production volumes and the anticipated production mix; the
proportion of our anticipated oil and gas production that is hedged; our drilling program including future development and drilling locations and plans, the results from our
drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; expectations
regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; future efficiencies and reserves and production growth;
anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating costs; capital spending levels in 2014 and its impact on our production
level; potential future asset impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our
future U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. taxes; future funds flow levels; future
debt and working capital levels and debt-to-funds-flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working
capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected proceeds therefrom
and production volumes associated therewith.
The forward-looking information included in this presentation is not a guarantee of future performance and should not be unduly relied upon. Such information involves
known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking
information including, without limitation: changes in commodity prices; changes in realized prices for Enerplus’ products; changes in the demand for or supply of Enerplus'
products; unanticipated operating results, results from development plans or production declines; changes in tax or environmental laws, royalty rates, incentive programs or
other regulatory matters; changes in development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements;
inaccurate estimation of Enerplus' oil and gas reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of
adequate insurance coverage; the impact of competitors; reliance on industry partners; constraints on, or unavailability of, adequate pipeline and transportation capacity;
and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F
described below and under “Risk Factors and Risk Management” in our MD&A for the year ended December 31, 2013).
The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions made by Enerplus including, without limitation:
that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of
current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and
resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and funds flow to fund our capital, operating
and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility
to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. We believe the material factors, expectations and assumptions
reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information contained in this presentation speaks only as of the date of this presentation, and none of Enerplus or its subsidiaries assume any
obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
1
Advisories
Assumptions
All amounts are stated in Canadian dollars unless otherwise specified.
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
This presentation contains references to "BOE" (barrels of oil equivalent) and "Bcfe" (billion cubic feet of gas equivalent). Enerplus has adopted the standard of six thousand cubic
feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs, and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Bcfes .
BOEs and Bcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at
the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly
different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million
barrels of oil equivalent", respectively.
Non-GAAP Measures
In this presentation, we use the terms "funds flow", “free cash flow”, “capital efficiency”, and “recycle ratio” as measures to analyze operating performance, leverage and
liquidity. “Funds flow” is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation
expenditures. “Debt to funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The debt to funds flow ratio is
calculated as total debt net of cash, divided by a trailing 12 months of funds flow. “Adjusted payout patio” is used by Enerplus and is useful to investors and securities analysts in
analyzing operating performance, leverage and liquidity. We calculate our adjusted payout ratio as dividends to shareholders, net of our Stock Dividend Program (“SDP”) proceeds,
plus capital spending (including office capital) divided by funds flow. “Free cash flow” is calculated as net operating income (netback) less capital expenditures. “Capital efficiency” is
calculated as the change in production from the fourth quarter of the previous year to the fourth quarter of the current year divided by total capital expenditures from the fourth
quarter of the previous year up to and including the third quarter of the current year. A “recycle ratio” is calculated as finding and development costs divided by operating netback.
Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow", "capital efficiency”, and “recycle ratio” are useful
supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by
U.S. GAAP and do not have a standardized meaning prescribed by U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures
presented by other issuers.
Presentation of Production and Reserves Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under IFRS and Canadian
industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. In order to continue to be comparable with our Canadian
peer companies, the summary results contained within this presentation presents our production and BOE measures on a before royalty company interest basis. In addition, initial
test results and production performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate
recovery.
All production volumes and revenues presented herein are reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest.
Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company interest reserves" using forecast prices and
costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101)), being
2
Advisories
Enerplus' working interest before deduction of any royalties), plus Enerplus' royalty interests in reserves. “Company interest reserves" are not a measure defined in NI 51-101 and
do not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our
oil and gas reserves statement for the year ended December 31, 2013, includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance
with NI 51-101, is contained within our Annual Information Form for the year ended December 31, 2013 ("our AIF") which is available on our website at www.enerplus.com and
under our SEDAR profile at www.sedar.com. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on
EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial statements filed on SEDAR and as part of our Form 40-F on
EDGAR concurrently with this presentation for more complete disclosure on our operations.
Discovered Petroleum Initially-In-Place
Discovered Petroleum Initially-In-Place (“PIIP”) is that quantity of petroleum that is estimated to be contained in known accumulations prior to production. The recoverable portion of
discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable. Discovered Original Oil in Place (“OOIP” ) is not defined in NI 51-101 and
does not have a standardized meaning under NI 51-101. Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP for our North
Dakota assets were provided by an independent estimate by McDaniel & Associates dated June 9, 2014 and as of June 1, 2014. Discovered OOIP pertaining to our waterflood
assets are estimates by internal qualified reserves evaluators, combined for all core waterfloods.
Contingent Resource Estimates
This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. The estimates of contingent
resources included in this presentation pertaining to Fort Berthold and Canadian Gas-Deep Basin properties were evaluated by Enerplus and audited by independent reserve
evaluators, McDaniel & Associates. The estimates of “contingent resources” included in this presentation pertaining to the U.S. Core Gas-Marcellus were evaluated by independent
reserves evaluators, Netherland, Sewell & Associates. The estimates of “contingent resources” included in this presentation pertaining to Canadian Waterflood Assets were
evaluated by internal qualified reserves evaluators. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those
quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but
which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economics, legal, environmental,
political and regulatory matters or a lack of markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associated with a
project in the early evaluation stage. All of our “contingent resources” estimates are economic using established technologies and under current commodity price assumptions used
by our independent reserve evaluators. Enerplus expects to develop these “contingent resources” in the coming years however it is too early in their development for these
resources to be classified as reserves at this time. There is no certainty that we will produce any portion of the volumes currently classified as “contingent resources”. The
“contingent resources” estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered. The “contingent resources” estimate
pertaining to Fort Berthold is effective as of June 1,2014. All other “contingent resources” estimates are effective as of December 31, 2013. A "best estimate" of contingent
resources” means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there
should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.
For additional information regarding the primary contingencies which currently prevent the classification of our disclosed “contingent resources” associated with our Marcellus shale
gas properties, our Fort Berthold properties, our Wilrich natural gas properties and a portion of our Canadian crude oil properties as reserves, and the positive and negative factors
relevant to the “contingent resource” estimates, see our AIF, a copy of which is available under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is
available under our EDGAR profile at www.sec.gov.
3
Advisories
See "Non-GAAP Measures" above.
Finding & Development (“F&D”)and Finding, Development & Acquisition (“FD&A”) Costs
F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs
incurred in the year plus the change in estimated proved future development costs in the year, by the additions to proved reserves in the year, and (ii) in the case of
F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated proved plus
probable future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs
incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs
related to its reserves additions for that year.
FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs
and the cost of net acquisitions incurred in the year plus the change in estimated proved future development costs in the year, by the additions to proved reserves
including net acquisitions in the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs
and the cost of net acquisitions incurred in the year plus the change in estimated proved plus probable future development costs in the year, by the additions to proved
plus probable reserves including net acquisitions in the year. The aggregate of the exploration and development and net acquisition costs incurred in the most recent
financial year and the change during that year in estimated future development costs generally reflect total finding, development and acquisition costs related to its
reserves additions for that year.
See "Non-GAAP Measures" above.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in this presentation has generally been prepared in accordance with Canadian disclosure standards, which are
not comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be
defined differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules. In addition,
under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes,
which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after
deduction of applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations,
while the SEC mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period. Additionally, the SEC prohibits
disclosure of oil and gas resources in SEC filings, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be
construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see “Contingent
Resource Estimates” above.
4
Enerplus Proven Strategy
Disciplined
Capital
Allocation
•
•
Robust, economically
grounded capital
allocation
Sustainable,
Organic
Growth &
Income
Strong
Financial
Position
•
Debt-to-funds flow ratio of
1.3x*
•
Significant organic drilling
inventory
•
$1 billion credit line
virtually unused*
•
13% per share production
growth in 2014
•
Significant hedge
positions in Q4 2014 and
2015
•
Long-term growth target of
5% ‒ 10%
•
Dividend yield ~6.5%
Capital efficiency target of
<$30,000 BOE/day
*As at September 30, 2014.
1
Strong Per Share Growth
Production/share
Funds Flow/share
0.20
4.50
0.18
0.16
$4.16
4.00
0.16
$3.76
0.15
3.50
0.14
$ Per Share
BOE per Share
0.18
0.12
0.10
0.08
3.00
2.50
2.00
0.06
1.50
0.04
1.00
0.02
0.50
-
$3.29
2012
2013
2014E*
2012
2013
* Based on mid-point of revised 2014 production guidance of 103,000 BOE/day and average shares outstanding.
** Analyst consensus at October 28, 2014.
2014E**
6
Sustainable Growth & Dividend
Strong funds flow growth supporting sustainable dividend
2012
2013
2014E
Funds Flow (MM)
$645
$754
$854 (1)
Capital Expenditures (MM)
$853
$681
$830
Net Acquisitions & Divestitures (MM)
($91)
($120)
Dividends (MM)
$302
$217
$220
SDP Proceeds (MM)
($43)
($46)
($20)
Adjusted Payout Ratio (APO)
174%
114%
120% (3)
APO, net of A&D
158%
97%
96%
1.7x
1.4x
D/FF ratio
1)
2)
3)
($208) (2)
1.3x
Analyst consensus at October 28, 2014.
At November 6, 2014.
At September 30, 2014. Funds flow used for APO calculation is based on analyst consensus at October 28, 2014.
(3)
7
Q3 2014 Results—Continued Performance
Low-end of production guidance increased by 2,000 BOE/day

102,000 – 104,000 BOE/day annual average estimate in 2014, despite
the sale of 3,500 BOE/day of non-core divestments
Non-core divestments— two new transactions completed

3,100 BOE/day sold for proceeds of $91 million

YTD proceeds from divestments of over $200 million
Capital spending – increased as a result of net proceeds from divestments
 Modest capital increase of $30 million to $830 million
Continued productivity improvements in key growth areas

Fort Berthold – YTD avg 30 day IP rate 20% above high type curve estimate

Marcellus – 25% capital efficiency improvement year-over-year
8
Funds Flow Protection
WTI Crude Oil Hedge Positions*
Natural Gas Hedge Positions*
Rest of 2014
Rest of 2014
AECO Swaps C$4.25/Mcf
10%
51%
36%
NYMEX Collars
11% US$4.30 - $5.08/Mcf
US$95.29/bbl
64%
28%
NYMEX Swaps US$4.14/Mcf ***
12%
C$4.125
2015
2015
62%
72%
US$93.68/bbl **
38%
25% NYMEX Swaps US$4.21/Mcf
3%
Q1 NYMEX Collars US$4.53 - $5.53/Mcf
* As of Oct 22, 2014, based on weighted average price (before premiums), assuming mid-point annual average
production of 103,000 BOE/day for 2014 & 2015, less royalties of 23%.
** Include 6% (2000 bbls/day) protected at $93.64/bbl with upside participation above $94.00/bbl
*** Includes 9% (25 MMcf/day) protected at $4.17/Mcf with upside participation to $5.00/Mcf.
9
Core Areas
U.S.
Gas
10
U.S. Core Oil:
Fort Berthold, North Dakota
Key Facts
Discovered OOIP
Discovered OOIP (W.I.)
1.5 billion bbls
Net Acreage
73,000 acres
(114 sections)
2P Reserves at Dec 31, 2013
105 MMBOE
Best Est. Economic Contingent
Resources June 1, 2014
136 MMBOE
Future Net Drilling Locations
PUDs
Contingent Resources
Q3 2014 Production
Net Locations Drilled to Date
•
Bakken

Three Forks

Drilling/ WOC
330 wells
(98)
(232)
22,400 BOE/day
125 wells
(93 Bakken/32 Three Forks)
2014 Focus:

~90% W.I.
20 – 42 MMbbls/1280 DSU

Productivity improvements through:
Down spacing tests
Delineation of Lower Three Forks
Completion optimization
11
Fort Berthold Delivering Growth
Annual Production
25
Reserves
2P:
105.4
22
17
80
15
MMBOE
MBOE/day
2P:
86.1
100
20
12
10
2P:
56.2
60
40
2P:
22.5
5
5
20
0
0
2011
2012
2013
1P:
28.0
1P:
11.7
2014E
2010
2011
Total Proved
•
2014E annual production growth of ~30%
•
•
*Free cash flow is calculated as NOI less capital expenditures.
1P:
49.6
1P:
43.7
2012
2013
Probable
Replaced 400% of 2013 production adding 24.9 MMBOE
of reserves at F&D cost (incl. FDC) of $19.74/BOE
Three year F&D cost of $21.56/BOE
12
Fort Berthold:
127% Increase in Drilling Inventory
Original View
4 wells/
DSU
New View
Avg. 7 wells/
DSU
Bakken—Long
53
124
Three Forks—Long
66
89
119
213
21
63
5
53
26
116
145
329
Locations
Bakken—Short
Three Forks—Short
Total Net Future
Drilling Locations*
* Includes undeveloped reserves and contingent resources locations.
• 184 new locations added
 Two thirds of locations are
long laterals
• Average 7 wells per spacing
unit with maximum of 8 wells
per unit
• Average EUR per well


Long 625 Mbbls/750 MBOE
Short 320 Mbbls/385 MBOE
13
Improving Productivity through Completion
Enhancements
14
Fort Berthold:
Improving Capital Efficiencies*
25,000
• Reduction in well
costs and significant
increase in IP rates
driving top quartile
capital efficiencies
$20,500
Capital Efficiency ($K/BOE/day)
20,000
$18,000
$15,500
15,000
$11,500
$11,000
10,000
$8,000
5,000
• On-going focus on
completion evolution
and cost improvement
2012
Ceramic:
23-29 Stages
(~275 lbs/ft)
2013
Ceramic:
28 Stages
(~325 lbs/ft)
2013
White Sand:
28 Stages
(~750 lbs/ft))
2013
White Sand:
35-38 Stages
(~750 lbs/ft)
2013
White Sand:
36-42 Stages
(~1000 lbs/ft)
* Capital efficiency based upon 30 day initial production rates
2014
White Sand:
36-42 Stages
(~1000 lbs/ft)
15
Fort Berthold Completion Performance
Improving Economics*
30 Day Cum Prod (bbls)
Old Type Curve
High EUR
Low EUR
800 Mbbls 500 Mbbls
(950 MBOE) (600 MBOE)
23,000
15,000
New Type Curve
High EUR
Low EUR
800 Mbbls
530 Mbbls
(950 MBOE) (635 MBOE)
43,000
31,000
1st Year Cum Prod (bbls)
155,000
98,000
243,000
165,000
NPV 10% ($MM)
$11.08
$2.34
$13.76
$4.67
45%
15%
80%
30%
Payout (Yrs)
2.1
4.5
1.3
2.6
Recycle Ratio
Capital ($MM)
3.3
11.5
2.0
11.5
3.3
12.0
2.2
12.0
IRR Btax (%)
* Assumes US$85/bbl WTI flat crude oil price and US$4.00/Mcf NYMEX natural gas price; based on long Bakken horizontal wells.
16
Fort Berthold Completions Enhancements
Leading to Best in Basin Well Results
First 6 Calendar Month Liquids Production* (bbls)
First Six Calendar Months
E+ Best
Bakken
Enerplus wells drilled without high volume completions
E+ Best
Three Forks
Enerplus wells drilled with high volume completions
volume completions
Well Count
* Long horizontal wells only (>6,000’ lateral). Data set ~6,300 wells, at November 1, 2014.
17
Low Decline Canadian Waterflood Assets
Key Facts
Discovered OOIP (W.I.)
1.3 billion bbls
Recovery Factor * to Date
24%
2P Reserves at Dec 31, 2013
87 MMBOE
Best Est. Economic Contingent
Resources Dec 31, 2013
59 MMbbls
EOR & IOR
Future Net Drilling Locations
Q3 2014 Production
160 wells
20,000 BOE/day
Average Decline Rate
14%
•
Core area representing almost half
of corporate liquids production
•
Lower growth profile with low decline
•
Primary, secondary and tertiary oil
recovery opportunities
* Estimated by internal qualified reserves evaluators. Represents the combined production for all core waterfloods divided by the
combined discovered OOIP for all core waterfloods.
18
Free Cash Flow from Waterflood Assets
$350
$300
NOI:
$266
NOI:
$287
$ Million
NOI:
$320
$172
$137
$250
NOI:
$301
$179
NOI:
$272
$77
$124
$200
• Significant free cash
flow generation with
reinvestment around
55% annually
72%
$150
53%
$100
• 2014 capital higher
with Brooks program
46%
52%
41%
$50
$0
2010
2011
Capital
2012
2013
2014E*
Free Cash Flow
* Based on September 30, 2014 forward curve and 2014 corporate differential assumptions. Free cash flow is calculated as
NOI less capital expenditures; adjusted for acquisitions and divestitures.
19
Thickness
U.S. Core Gas: Marcellus
Enerplus Land
Key Facts
Marcellus Well
Net Acreage
2P Reserves Dec 31, 2013
53,300 acres
601 Bcf
Best Est. Economic Contingent
Resources Dec 31, 2013
1,340 Bcf
Future Net Drilling Locations
240 wells
Q3 2014 Production
187 MMcf/day
• Concentrated, non-op
position in NE Pennsylvania
• Marcellus Q3 production
represents 52% of corporate
natural gas volumes
Pennsylvania
• 60% of core acreage held by
production
28% W.I.
20
Marcellus Delivering Growth
2P:
601
Reserves
Annual Production
180-200
200
600
180
500
Bcf of Natural Gas
160
MMcf/day
140
120
95
100
80
60
400
300
200
41
40
1P:
411
2P:
154
2P:
117
100
21
20
2P:
225
1P:
52
-
1P:
146
1P:
93
0
2011
•
2012
2013
2014 >90% production growth forecast
2014E
2010
•
•
•
2011
Total Proved
2012
Probable
2013
2013 proved plus probable reserves increased by 168%
50% of corporate 2P natural gas reserves
2013 2P F&D of $0.58/Mcf & FD&A of $0.91/Mcf
21
Marcellus: Superior Dry Gas Performance
and Competitive Economics
Tighter stage spacing and increased proppant continues to improve performance
2013 - 2014 Gross On-Streams
US$ 4.50/Mmbtu
IP30, MMcf/d
IRR, %
PV10, $MM
Capital, $MM
EUR
8 Bcf
11
23
2.4
6.9
EUR
12 Bcf
16
54
7.1
6.9
EUR
13 Bcf
10
56
7.6
6.9
EUR
16 Bcf
21
90
11.7
6.9
US$ 4.00/Mmbtu
IRR, %
PV10, $MM
13
0.5
33
4.3
35
4.6
58
8.0
The 13 BCF EUR case reflects infrastructure constrained
production, with lower IP30
Differentials: 2014: -$1.35
2015: -$1.50
2016: -$1.25
2017 & beyond: -$0.50
22
Core Canadian Natural Gas—Deep Basin
•
Core growth area with
approximately 450
potential net future
drilling locations in the
Wilrich and Duvernay
•
160,000 net acres of
high working interest
land
•
Successful drilling
results to date in
Wilrich—moving to
development
•
Advancing appraisal on
Duvernay lands
Duvernay
85,000 net acres of
undeveloped land,
100% WI
Stacked Mannville
76,000 net acres of land
(60,000 net acres of land
in the Wilrich, majority
100% WI)
23
Duvernay Shale—Willesden Green
R12W5
R11W5
R10W5
R9W5
R8W5
R7W5
R6W5
R5W5
R4W5
R3W5
Producing
Wells
Drilled Wells
Locations
ENERPLUS Hz 15-8-46-9W5M
On production 10/2014
IP30 ~700 Boepd (58%
liquids)
•
85,600 net acres (100% W.I.)
•
Core analysis from 4 vertical tests
supports a range of free condensate
yields across a significant portion of
acreage
ENERPLUS Vt 13-7-455W5M
Rig Released: 8/30/2013
Cored, logged and reentered
ENERPLUS Vt 1-35-4510W5M
Rig Released: 10/23/2013
Cored, logged and prepped
for future re-entry
•2 horizontal wells completed and placed
on production to-date with positive results
ENERPLUS Hz 1-7-45-5W5M
On production 6/2014
IP30 ~535 Boepd (30% liquids)
 1-7-45-5W5M average 30 day IP rate of 535
BOE per day including 2.24 MMcf per day of
sales gas with 162 barrels per day of total
liquids, 53% condensate
ENERPLUS Vt 11-26-459W5M
Rig Released: 10/26/2012
Cored and logged
 15-8-46-9W5M average 30 day IP rate of
700 BOE per day, including 1.75 MMcf per
day of sales gas, with 410 barrels per day of
liquids, roughly 85% condensate
R12W5
R11W5
R10W5
R9W5
R8W5
R7W5
R6W5
R5W5
R4W5
•
Future development at 3 - 4 wells per
section provides 300 - 400 Hz potential
drilling locations
•
Continued evaluation of well results and
focus on improving well costs
R3W5
24
Our Competitive Advantage
• Focused portfolio in top tier resource plays: Bakken/Three Forks,
Marcellus, Deep Basin & Waterfloods
• Continued focus on capital discipline—delivering 13% production/share
growth in 2014 with a target capital efficiency of <$30,000/BOE/day
• Low corporate decline rate
• Significant inventory of economic growth prospects: ~830 future
drilling locations* & sizeable upside
• Affordable growth supported by a strong balance sheet
• Delivering profitable growth with an attractive yield
* 2P reserves and contingent resource locations at December 31, 2013; Fort Berthold contingent resource
assessment completed June 1, 2014.
25
Supplemental Information
Significant Organic Growth Potential
Core
Waterfloods
Additional Upside:
Fort Berthold
Primary Drilling
Secondary Recovery
Tertiary Recovery
Fort Berthold
16 years
160
Locations
•
Downspacing opportunities
Duvernay
• 85,000 net acres prospective
for natural gas liquids
330
Locations
Torquay
Marcellus
15 years
240
Locations
100
Locations
Deep Basin (Wilrich)
10 years
• Canadian Three Forks play
• 92,160 acres
 144 sections
(100% W.I.)
Sleeping Giant (Montana)
• Possible enhanced oil recovery
opportunity
* 2P reserves and economic contingent resources locations at December 31, 2013 and as at June 1, 2014 for
Fort Berthold economic contingent resources assessment. Based on current development plans.
27
Demonstrated Growth
Reserves**
Annual Production
103
350
59
42
60
48
42
40
MMBOE
MBOE/day
75
70
50
406
400
82
90
80
450
90
100
306
43%
300
250
200
346
322
43%
49%
40%
47%
150
30
20
100
33
40
42
44
10
50
0
0
2011
2012
Oil & Natural Gas Liquids
2013
2014E*
Natural Gas
49%
53%
55%
47%
2010
2011
2012
2013
Liquids
* Based upon mid-point of 2014 production guidance of 102,000—104,000 BOE/day.
** Proved plus probable company interest reserves at December 31.
Crude Oil
Natural Gas
28
Competitive Reserve Addition Costs
FD&A Costs*
F&D Costs*
$30
$30
$26.26
$24.21
$25
$20
3 year:
$19.25
$15
$/BOE
$/BOE
$25
$20
$22.92
$17.89
3 year:
$14.66
$15
$11.28
$10
$10
$5
$5
$8.36
$0
$0
2011
2012
2013
2011
2012
2013
* Based on proved plus probable company interest reserves at December 31, including future development costs. FD&A is
defined as finding, development & acquisitions (net of dispositions).
29
2014 Funds Flow Sensitivities
Est. effect on
2014 Funds Flow
($ Million)
Est. effect on
2014 Funds Flow per Share
($/share)
Change of $5.00/bbl WTI crude oil
$5.5
$0.03
Change of $0.50/Mcf NYMEX natural gas
$8.0
$ 0.04
Change of 1,000 BOE/day production for rest of year
$2.5
$0.01
Change of $0.01 in the US$/CDN$ exchange rate
$1.9
$0.01
2014 Sensitivities
* The sensitivities above reflect our forecasts, outstanding commodity contracts, approximately 204.5 million
outstanding shares, and are based on forward markets as at October 22, 2014.
30
Operated Light Oil Assets in the
Williston Basin
2014E Production: 28,000 BOE/day
Sleeping
Giant
20%
Fort
Berthold
80%
2013 2P Reserves*: 131 MMBOE
Sleeping Giant
(Elm Coulee)
Fort
Berthold
Sleeping
Giant
20%
Dunn
80%
Fort
Berthold
Enerplus lands
* Company interest reserves at December 31, 2013.
31
Consistent Production Growth in Fort
Berthold
2014E AA: 22,000 BOE/day
30,000
25,500
25,000
2013 AA: 16,500 BOE/day
Boe/day
20,000
18,035
18,206
18,310
Q3 2013
Q4 2013
Q1 2014
20,790
22,359
Q2 2014
Q3 2014
15,169
14,576
15,000
10,000
5,000
Q1 2013
Q2 2013
FTB Production
•
•
Q4 2014 (Est)
Annual
Average
Production
2013
Annual
Average
Production
Q3 2014 production has grown 24% since the same period in 2013
Expect to bring 5.6 net wells on-stream in Q4
32
Fort Berthold:
250% Increase in Contingent Resources
Original
Assumption
2014
Evaluation
Increase
8 – 12 MMbbls
8 – 10 MMbbls
n/a
16 – 22 million bbls
8 – 16 MMbbls
10 – 16 MMbbls
2 – 20 MMbbls
20 – 42 million bbls
4 – 20 MMbbls
TOTAL WI Discovered OOIP
1 billion bbls
1.5 billion bbls
500 MMbbls
2P Reserves @ Dec. 31, 2013
105 MMBOE
105 MMBOE
-
39 MMBOE
136 MMBOE
97 MMBOE
100%
70%
n/a
100%
100%
35%
Discovered OOIP per DSU*
Bakken
TF1
TF2
Total
Contingent Resources
Utilization Assumptions:
Bakken
TF1
TF2
* Per 1,280 acre drilling spacing unit (DSU).
33
Fort Berthold Well Density Schematic
6 / 7 Well Density*
8 Well Density*
TF 2 &3 Upside**
No Lower Three Forks
Stand-Alone Locations
Lower Three Forks
Productive
TF3 & Additional
TF Wells
* Assumes 15% recovery factor.
** ”Super Unit” equivalent to lease line drilling.
34
Fort Berthold:
Increasing to Average 7 Wells/DSU
Enerplus Hognose
Successful TF2
Northwest
• Highest estimate of discovered OOIP
• Includes TF2
• 8 well density
Enerplus
Butterflies TF2
Drilling
8
Central/West
• Well density ranging from 6 – 8 wells
depending upon discovered OOIP and TF2
prospectivity
6,7,8
Central/South
Industry
TF2/TF3
Planned
6 or 7
• Planned for 6 or 7 well density depending
upon discovered OOIP and recovery factor
35
Fort Berthold:
Encouraging Enerplus High Density Tests
300
Snakes Pad
8 Well Density & TF2
250
Snakes Pad
Butterflies/Turtles* pad
8 Well Density & TF2
Fur Bearers pad
7 Well Density
Cum. Oil (Mbbls)
200
Fur Bearers Pad
100
50
Enerplus down spacing test
(7 well density)
Enerplus down spacing test &
TF2 test
Enerplus down spacing test &
TF2 test
TF1
2
Bakken
4
6
8
10
Months on Production
Three Forks
Drilling/ WOC
* Butterflies/Turtles pad on-stream early November
36
Fort Berthold Completion Evolution
Increasing Production Rates
$350
$319
Completion Costs/Stage
• Despite larger fracs, the
switch to sand and
effective cost
management has helped
reduce completion costs
$300
$241
US$K
$250
$221
$215
$216
$195
$200
$150
$100
$50
$-
30 Day Cum. Oil
Oil (Mbbls)
70
60
BKN
TF
60
50
45
40
40
30
20
34
32
27
21
18
22 20
22
10
-
• Significant increase in
30 day cumulative
production from high
intensity fracs
-
# Wells:
17 Bkn / 6 TF
3 Bkn / 1 TF
2 Bkn / 0 TF
2 Bkn / 2 TF
6 Bkn / 3 TF
2 Bkn / 3 TF
37
Fort Berthold Completions Enhancements
Leading to Best in Basin Well Results
Peak Calendar Month
Peak Calendar Month Cumulative Production* (bbls)
E+ Best Bakken
E+ Best Three Forks
Enerplus wells drilled without high volume completions
Enerplus wells drilled with high volume completions
volume completions
Well Count
* Long horizontal wells only (>6,000’ lateral). Data set ~7,000 wells, at November 1, 2014.
38
Fort Berthold U.S. Crude Marketing
•
~540,000 bbls/day of regional pipe capacity currently
available and another 200,000 bbls/day coming into
service after 2016
•
Rail loading capacity is plentiful with > 1.2 MMbbls
available at more than 16 unit train facilities
•
Current take-away capacity exceeds regional production
by 60%
•
Enerplus seeks to maintain a balanced approach to
marketing commitments
Available Capacity
Pipe
31%
Rail
69%


13,500 bbls/day of firm regional egress commitments
currently in place
5,000 bbls/day firm commitment made to Sandpiper
project to Clearbrook expected in late 2017 or early
2018
* Refers to August 2014 North Dakota and Montana production of ~1.2 MMbbls per NDIC and Montana Board of Oil
and Gas Conservation reports.
39
Fort Berthold:
Natural Gas and NGL Production
Fort Berthold
(Q3 2014 BOE/day)
6%
• Gas and NGLs are gathered and marketed
by our gatherer at market netback pricing
7%
• Realized natural gas price is higher than
NYMEX because of higher heat content
• Enerplus has been proactively focused on
gas conservation
87%
Oil
$12.00
Liquids

~80% of our wells are connected to gas
gathering; increasing by year-end

All wells are being equipped with high
efficiency flares as back-up in case of
disruptions
Realized Gas Price
$10.00
Ft. Berthold
(1300 BTU factor)
$8.00
Nymex
$6.00
$4.00
$2.00
Sep-14
Jul-14
May-14
Mar-14
Jan-14
Nov-13
Sep-13
Jul-13
May-13
Mar-13
Jan-13
Nov-12
Sep-12
Jul-12
May-12
Mar-12
$Jan-12
US$/Mcf
Gas
40
Brooks Overview
R14
R13
R12
32
33
34
35
36
31
32
33
34
35
36
31
32
33
29
28
27
26
25
30
29
28
27
26
25
30
29
28
North
S
R11W4
34
35
36
31
32
27
26
25
30
29
23
24
19
20
21
22
23
24
19
20
15
14
13
18
17
16
15
14
13
18
17
10
11
12
7
8
9
10
11
12
7
8
20
21
22
23
24
19
20
21
22
17
16
15
14
13
18
17
16
8
9
10
11
12
7
8
9
Key Facts
S
Discovered OOIP
223 MMbbl
Recovery Factor to Date
27%
2P Reserves at Dec 31, 2013
9 MMBOE
Best Estimate Contingent Resource
Dec 31, 2013
1.7 MMBOE
Cumulative Oil Production to Date
61 MMbbl
2014E Production
2,750 BOE/day
Average Base Decline Rate
12%
T20
T20
S
S
5
4
3
32
33
34
35
36
31
32
29
28
27
26
25
30
29
24
19
20
21
2
1
6
5
4
3
2
1
6
5
32
33
34
35
36
31
32
29
28
27
26
25
30
29
20
21
22
23
24
19
20
13
18
17
3
2
1
6
5
33
34
35
36
31
28
27
26
25
30
22
23
24
19
4
S
20
21
22
23
17
16
15
14
13
18
17
16
15
14
13
18
17
16
15
14
8
9
10
11
12
7
8
9
10
11
12
7
8
9
10
11
12
7
8
5
4
3
2
1
6
5
4
3
2
1
6
5
4
3
2
1
6
5
T19
T19
32
33
34
35
36
31
32
33
34
35
36
31
32
33
34
35
36
31
32
29
28
27
26
25
30
29
28
27
26
25
30
29
S
29
28
27
26
25
30
20
21
22
23
24
19
20
21
22
23
24
19
20
21
22
23
24
19
20
17
16
15
14
13
18
17
16
15
14
13
18
17
16
15
14
13
18
17
8
S
T18
T18
8
9
10
11
12
7
8
9
10
11
12
7
8
9
10
11
12
7
5
4
3
2
1
6
5
4
3
2
1
6
5
4
3
2
1
6
5
32
33
34
35
36
31
32
33
34
35
36
31
32
33
34
35
36
31
32
29
28
27
26
25
30
29
28
27
26
25
30
29
28
27
26
25
30
29
South
20
21
22
23
24
19
20
21
22
23
24
19
20
21
22
23
24
19
20
17
16
15
14
13
18
17
16
15
14
13
18
17
16
15
14
13
18
17
8
9
10
11
12
7
8
9
10
11
12
7
8
9
10
11
12
7
8
5
4
3
2
1
6
5
4
3
2
1
6
5
4
3
2
1
6
5
T17
• Potential to drill 60 locations over the next two+
years
T17
T16
T16
32
33
34
R14
35
36
31
32
33
34
R13
35
36
31
32
33
34
R12
35
36
31
32
R11W4
100% Working Interest
• Lower Mannville/Basal Quartz (~1,000 m depth)
• Currently running two rigs in Brooks South
• Early production performance has been positive
with average results in-line with our type-curve
expectations
41
Marcellus Production Growth
300
2014E AA: 190 MMcf/day
250
MMcf/day
200
190
189
187
Q2 2014
Q3 2014
179
150
2013 AA: 95 MMcf/day
131
100
79
88
83
Q2 2013
Q3 2013
50
Q1 2013
Q4 2013
Total Marcellus Production
Q1 2014
Q4 2014 (Est)
Annual Average Production
42
Marcellus Well Cost & Performance
Evolution
Total Well Cost
12,000
$10,000
30 Day Capital Efficiency
$8,000
$7,000
8,000
6,000
4,000
8,000
2,000
$7,500
7,000
2012
2013
$/BOE/day
0
2014
Initial Production
12
10
$5,500
6,000
5,000
$4,000
4,000
3,000
8
IP30
MMcf/day
$ Thousands
10,000
6
4
2,000
IP60
1,000
IP90
0
2012
2
2013
2014
2012
2013
2014*
* 2014 production rates include curtailment.
43
Marcellus Sales Price Mix – Q3 2014
TGP Z4 300
Spot: 34%
Dominion
South:
36%
Transco Leidy
Spot:
22%
Remainder priced at:
TETCO M3 (NY), TGP 500
(Tennessee) and TGP Z4
200 (Ohio)
* Map Source: Kinder Morgan.
Transco Z6
NNY:
3%
• Regional firm, must-take
contracts of ~80 MMcf/day
plus ~10 MMcf/day of
pipeline capacity out of the
region held through 2015,
with remainder sold at spot
market
• Executed sales and
precedent transportation
agreements for up to 80
MMcf/day at Transco NonNew York to backfill our
must-take contracts starting
in 2016
44
Northeast U.S. Pipeline Projects:
>8 Bcf of Projects Planned
Project
Rose Lake 300
Pipeline
Owner
Incremental Takeaway
(MMcf/day)
Destination
In Service
TGP
KM
230
NE*
Q4 2014
NE
Q4 2014
330
Transco - Northeast Connector
Transco
Williams
100
Transco - Rockaway Lateral
Transco
Williams
647
NE
Q12015
Columbia East Side Expansion
TCO
Columbia
300
NE
Q3 2015
Niagara Expansion
TGP
KM
158
Canada
Q4 2015
Canada
Q4 2015
Northern Access 2015
1,123
NF
Nat Fuel
140
Transco
Williams
525
Southeast
Q4 2015
Constitution
Williams
650
NE/Canada
Q1 2016
Transco
Williams
192
NE
Q3 2016
Algonquin
Spectra
342
NE
Q4 2016
TGP
KM
72
NE
Q4 2016
NF
National Fuel
250
Canada
Q4 2016
Atlantic Sunrise
Transco
Williams
1,700
Southeast
Q3 2017
Atlantic Bridge
Algonquin
Spectra
100
NE
Q4 2017
NE
Q4 2017
NJ/Non NY
Q4 2017
NE
Q4 2018
NJ/Non NY
Q4 2018
Transco - Leidy Southeast
Constitution
Rock Springs Lateral
Algonquin Incremental Market (AIM)
Connecticut Expansion
Northern Access 2016
Susquehanna West Expansion
Penn East Project
Northeast Energy Direct (NED)
Diamond East
TGP
KM
145
PennEast
Pipeline
UGI, SJR, NJR, AGL
800
TGP
KM
800
Transco
Williams
* Internal sources, November 2014
1,000
1,506
2,745
1,800
45
Northeast Pa. Marcellus Pipeline
Infrastructure Future Takeaway Capacity
• Production growth could be
capped at 1.5 Bcf/day based
on the pace of expected
pipeline additions in the
NE Pa. Marcellus
• Could see basis relief by
2017/2018 as capacity
additions appear to be
sufficient to meet this pace of
production growth
Source: ERF estimates (as of Sep 2014)
46
Canadian Gas—Deep Basin (Wilrich)
Contiguous land blocks in highly prospective regions
Key Facts
Key properties
North Ansell – CORE FOCUS
- Finishing 2-well pad in
Q4 2014 with partners.
Completion and tie-in Q1
2015
Net Acreage (acres)
Edson, Ansell, Minehead,
Hanlan
60,000 acres
(92 sections, majority 100% WI)
2P Reserves Dec 31, 2013
Best Est. Economic Contingent
Resources Dec 31, 2013
Ansell – CORE FOCUS
Q4 2014 capital acceleration
- 3-well Wilrich pad
development
Future Net Hz Drilling Locations
62 Bcfe
253 Bcfe
>100 wells
Est. EUR/Well
5.0–7.0 Bcfe
Q3 2014 Stacked Mannville
Production
27 MMcf/day
•
Growth potential to 60+ MMcf/day
•
Ownership in existing infrastructure to support up to
50 MMcf/day
47
Wilrich Activity
• Operated activity for Q4 2014

Commencement of three-well
pad in Ansell
• Non-operated activity

Two-well pad in North Ansell
• rig release in Q4 2014
with expected on-stream
Q2 2015
• Results from both programs will
be evaluated for additional 2015
activity
AECO $4.00/Mcf
NPV10 ($MM)
EUR
7 Bcf
EUR
6 Bcf
EUR
5 Bcf
$6.7
$5.3
$3.9
IRR (%)
46
38
30
Payout (years)
2.0
2.4
2.8
IP30 (Mcf/day)
7,600
6,900
6,200
BESC ($/Mcf)
$2.23
$2.42
$2.65
$5.2
$4.0
$2.7
IRR (%)
36
29
23
Payout (years)
2.5
2.9
3.5
AECO $3.50/Mcf
NPV10 ($MM)
Assumptions:
Capital:
$7MM/well; assumes pad drilling
Liquids:
7-10 bbls/MMcf
48
Debt Composition at September 30, 2014
•
Bank Credit Facility - $1 billion
• 11 banks in Enerplus’ bank credit facility
Unused
Capacity
$942MM
• Unsecured, covenant-based with current
borrowing rate of less than 3%
Senior Notes*
US$966MM
CDN$70MM
• Credit facility matures October 31, 2017
•
Senior Unsecured Notes - CDN$1,036 MM
•
Notes are rated NAIC 2 and rank equally
with bank credit facility; average interest
rate of 5.3%
Bank Facility
$58MM
• On September 3, 2014 we closed a
US$200 million private placement of senior
unsecured notes with a 10 year average
life at an interest rate of 3.79%
*Canadian dollar equivalent of U.S. dollar denominated notes FX rate at September 30, 2014 US/CDN of 1.1208.
49
Senior Notes Maturities
Average interest rate of 5.3%*
$160
$147
$140
$130
$130
$124
$124
$ Millions
$120
$97
$100
$80
$80
$60
$51
$51
$45
$45
2025
2026
$40
$20
$12
$0
$0
2014
2015
2016
2017
2018
2019
* US$ amounts converted at US/CDN 1.1208.
2020
2021
2022
2023
2024
50
Enerplus Share Ownership
Investor Composition
Total Retail
60%
Geographic Composition
Total Institutional
40%
21%
36%
44%
56%
20%
24%
US & Other Retail
Canadian Retail
US & Other Institutional
Canadian Institutional
As of October 20, 2014
United States & Other
Canada
51
Enerplus Board of Directors
Elliott Pew, Chairman of the Board(1)(2)
Mr. Pew, Chairman of Enerplus, is a co-founder of Common Resources and served as its Chief Operating Officer until the company was sold in May, 2010. He is
currently a Director for the newly formed Common Resources II located in The Woodlands, Texas. Previously, Mr. Pew was Executive Vice President Exploration at Newfield Exploration Company in Houston where he led Newfield’s diversification efforts onshore in the late 1990’s in addition to leading the
company’s exploration program, including the formation of the deep water GOM business unit. Prior to Newfield, Mr. Pew was Senior Vice President - Exploration
with American Exploration Corp. Mr. Pew is a Geology graduate of Franklin and Marshall College and holds an M.A. in Geology from the University of Texas.
David H. Barr, Director (12)
Mr. Barr has 38 years of experience in the oil and gas industry, and is President and Chief Executive Officer of Logan International Inc., a company focused on
downhole tools and completion services. He was formerly Chairman of the Board of Logan International. He also spent close to 36 years with Baker Hughes in
various executive roles, including Group President of numerous divisions and President of Baker Atlas. He currently serves as a Director of ION Geophysical
Corporation and Probe Technology Services. Mr. Barr holds a B.S. Mechanical Engineering degree from Texas Tech University.
Michael Culbert, Director (3)(9)
Mr. Culbert brings over thirty years of diverse experience in the oil and gas industry in North America and is currently the President, Chief Executive Officer and a
Director of Progress Energy Canada Ltd. He brings a strong background in business development, economics and strategic planning and holds a Bachelor of
Science degree in Business Administration. He currently sits on the Board of Directors of Pacific NorthWest LNG Ltd. and is also a member of the Canadian
Association of Petroleum Producers’ Board of Governors.
Edwin V. Dodge, Director (9)(11)
Mr. Dodge is currently a corporate director following a 35-year career with Canadian Pacific Railway Limited ("CPR", a Canadian national rail carrier), where he
was Chief Operating Officer from 2001 until his retirement in March 2004. Prior to 2001, Mr. Dodge held other senior roles with CPR including Executive Vice
President of Operations for Canada and the U.S., as well as Chief Executive Officer of a Minneapolis-based railroad. Mr. Dodge holds a Civil Engineering degree
and an MBA from the University of Western Ontario.
Ian C. Dundas, Director
Mr. Dundas became President and Chief Executive Officer of Enerplus on July 1, 2013. He joined the company in 2002 as Vice-President of Business
Development, with accountability for all corporate acquisition and divestment strategies. In 2010, his role expanded to that of Executive Vice-President. In 2011,
his responsibilities were further expanded to include the role of Chief Operating Officer, overseeing the development and execution of the company’s operational
strategies, strategic planning, marketing, reserves, as well as acquisitions and divestments. As President and Chief Executive Officer, Mr. Dundas is responsible
for overall leadership of the strategic and operational performance of Enerplus.
Enerplus Board of Directors continued
Hilary Foulkes, Director (5)(11)
Ms. Foulkes has more than 30 years of experience within the Canadian oil and gas industry focused in the areas of exploration, development and investment
banking. She has held executive roles in both investment banking and oil and gas operations, including Executive Vice-President and Chief Operating Officer for
Penn West Petroleum Ltd. She is a professional geologist and earned a Bachelor of Science (Honours, Earth Sciences) from the University of Waterloo. Her
career highlights include being the architect and lead negotiator of award-winning, multi-billion dollar international joint ventures.
James B. Fraser, Director (7)(11)
Mr. Fraser has over 35 years of energy industry experience, and was the Senior Vice President for the shale division of Talisman Energy Inc.'s North American
operations. From 2006 to 2008, Mr. Fraser was Vice President of operations for the southern division of Chesapeake Energy and prior to this spent over 20 years
at Burlington Resources and its predecessor companies, where he held a number of senior positions including North American Exploration Manager. Mr. Fraser
holds a MBA from Regis College and a Bachelor of Science in Petroleum Engineering from the Montana School of Mines.
Robert B. Hodgins, Director (3)(6)
Mr. Hodgins has been an independent businessman since November 2004. Prior to that, Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy
Trust (a TSX and NYSE-listed energy trust) from 2002 to 2004. Prior to that, Mr. Hodgins held the position of Vice President and Treasurer of Canadian Pacific
Limited (a diversified energy, transportation and hotels company) from 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited (a TSX
and NYSE-listed energy transportation company) from 1993 to 1998. Mr. Hodgins received a Bachelor of Arts in Business from the Richard Ivey School of
Business at the University of Western Ontario in 1975 and received a Chartered Accountant designation and was admitted as a member of the Institute of
Chartered Accountants of Ontario in 1977 and Alberta in 1991.
Susan M. MacKenzie, Director (7)(10)
Ms. MacKenzie has over 25 years of energy sector experience, most recently serving as Chief Operating Officer with Oilsands Quest Inc. in 2010. Prior to that,
Ms. Mackenzie enjoyed a 12-year career at Petro-Canada where she held senior roles including Vice-President of Human Resources and Vice President of In
Situ Development & Operations. Ms. MacKenzie was also with Amoco Canada for 14 years in a variety of engineering and leadership roles in natural gas,
conventional oil and heavy oil exploitation. Ms. MacKenzie holds a Bachelor of Engineering (Mechanical) degree from McGill University, an MBA from the
University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA).
Donald J. Nelson, Director (3)(9)
Mr. Nelson has over 40 years of experience in the oil and gas industry, and is the president of Fairway Resources Inc., a private consulting services firm. Prior to
this, Mr. Nelson was with Summit Resources from 1996 to 2002, until its acquisition by Paramount Resources Ltd., where he held the position of Vice President
Operations from 1996 to 1998 and President and Chief Executive Officer from 1998 to 2002. He currently serves as Director for Perpetual Energy Inc., Keyera
Corp., as well as three other private companies. Mr. Nelson is a Professional Engineer, a member of the Association of Professional Engineers, Geologists and
Geophysicists of Alberta and of the Society of Petroleum Engineers.
Enerplus Board of Directors continued
Glen D. Roane, Director (4)(5)
Mr. Roane is a corporate director and currently serves as a director of Enerplus, Badger Daylighting Ltd., Logan International Inc., SilverBirch Energy Corporation
and the GBC American Growth Fund. Mr. Roane is also a member of the Alberta Securities Commission. Previously he served as a board member of many TSXlisted companies and private companies including Repap Enterprises Inc., Ranchero Energy Inc., Forte Resources Inc., Valiant Energy Inc., Maxx Petroleum Ltd.,
UTS Energy Corporation, Destiny Resource Services Ltd., NQL Energy Services Inc., Severo Energy Ltd., Flexpipe Systems Inc., and Tarpon Energy Services
Ltd. Mr. Roane retired from TD Asset Management Inc., a subsidiary of The Toronto-Dominion Bank in 1997. Previously he was a founding partner of Lancaster
Financial Inc., a financial advisory and investment management firm and was formerly employed by Burns Fry Limited and by the Toronto Dominion Bank. Mr.
Roane holds a Bachelor of Arts (1977) and an MBA (1979) from Queen's University in Kingston, Ontario and holds the ICD.D designation from the Institute of
Corporate Directors.
Sheldon B. Steeves, Director (5)(8)
Mr. Steeves has over 37 years of experience in the North American oil and gas industry and is currently a Director of Tamarack Valley Energy Ltd., a Canadian oil
and gas company with operations in the Western Canadian sedimentary basin. From January 2001 until April 2012, Mr. Steeves was Chairman and CEO of
Echoex Ltd., a junior private company focused on greenfield organic growth in Western Canada. Mr. Steeves spent over 15 years at Renaissance Energy where
he was appointed Chief Operating Officer in 1997. He holds a Bachelor of Science in Geology from the University of Calgary.
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Chairman of the Board
Ex-Officio member of all Committees of the Board
Member of the Corporate Governance & Nominating Committee
Chair of the Corporate Governance & Nominating Committee
Member of the Audit & Risk Management Committee
Chair of the Audit & Risk Management Committee
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Member of the Reserves Committee
Chair of the Reserves Committee
Member of the Compensation & Human Resources Committee
Chair of the Compensation & Human Resources Committee
Member of the Safety & Social Responsibility Committee
Chair of the Safety & Social Responsibility Committee
Investor Relations Contacts
Jo-Anne M. Caza
Vice-President, Corporate & Investor Relations
403-298-2273
jcaza@enerplus.com
1-800-319-6462
investorrelations@enerplus.com
www.enerplus.com
The Dome Tower
Suite 3000, 333 7th Ave SW
Calgary, AB Canada
T2P 2Z1
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